Patent Publication Number: US-7905286-B2

Title: Method and apparatus for sealing a hole made with a cased hole formation tester

Description:
BACKGROUND 
     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. 
     SUMMARY 
     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. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       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: 
         FIG. 1  is an exemplary wireline system according to one or more embodiments of the disclosure; 
         FIG. 2  illustrates a non-limiting example of forming a hole in the sidewall of a borehole using a bit and introducing a sealant to the hole, according to the disclosure; 
         FIG. 3  illustrates a non-limiting example of a sealed hole using at least a portion of the bit and sealant according to the disclosure; 
         FIG. 4  is an elevation view of an illustrative non-limiting example of a downhole tool according to the disclosure; 
         FIG. 5  is an elevation view of an illustrative bit according to the disclosure; 
         FIG. 6 . is another elevation view of an illustrative bit according to the disclosure; 
         FIG. 7  is yet another elevation view of an illustrative bit according to the disclosure; 
         FIG. 8  illustrates a non-limiting example of a method for forming and sealing a hole in a sidewall of a borehole according to the disclosure; and 
         FIG. 9  illustrates another non-limiting example of a method for forming and sealing a hole in a sidewall of a borehole according to the disclosure. 
     
    
    
     DESCRIPTION OF EXEMPLARY EMBODIMENTS 
       FIG. 1  is an exemplary wireline system  100  according to one or more embodiments of the disclosure. The wireline system  100  is shown disposed in well borehole penetrating earth formations  104  for making measurements of properties of the earth formations  104 . The borehole can be filled with a fluid having a density sufficient to prevent formation fluid influx. As shown, the borehole is reinforced with cement  140  and a casing  142  that support the borehole wall and prevent formation fluid influx. 
     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  FIG. 1  illustrates a non-limiting example of a downhole tool for forming and sealing a hole in a sidewall of the borehole, along with several examples of supporting functions that may be included on the tool string  106 . The tool string  106  in this example is a carrier for conveying several sections of the tool string  106  into the borehole. The tool string  106  includes an electrical power section  124 , an electronics section  126 , and a mechanical power section  128 . A mandrel section  130  is shown disposed on the tool string  106  below the mechanical power section  128  and the mandrel section  130  includes downhole tool  136  for forming and sealing a hole in a sidewall of the borehole. 
     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  FIG. 1 , the mechanical power section  128  may be configured to include any number of power generating devices to provide mechanical power and force application for use by the downhole tool  136 . The power generating device or devices may include one or more of a hydraulic unit, a mechanical power unit, an electro-mechanical power unit, or any other unit suitable for generating mechanical power for the mandrel section  130  and other not-shown devices requiring mechanical power. 
     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  FIGS. 2 and 3 , an illustrative non-limiting downhole tool  200  according to one or more embodiments is shown.  FIG. 2  shows the downhole tool  200  forming a hole through the casing  142 , cement  140  and into the formation  104  using a bit  209 . For simplicity and ease of description, the borehole will be further described in the context of a cased borehole reinforced with cement  140  and a casing  142 . However, it is understood that open boreholes or other types of reinforced boreholes are also contemplated and within the scope of this disclosure. For example, in another embodiment, in an open borehole, that is the borehole wall is unsupported by a casing, cement, or other support system, the downhole tool can form a hole through the borehole wall and into the formation  104  using the bit  209 . The tool string  106  can include a port  215  through which the bit  209  can extend to contact the casing  142 . In one or more embodiments, a durable rubber pad  218  can be disposed about the port  215  such that the pad  218  contacts the casing  142 . The pad  218  may be pressed against the casing  142  with enough force to form a seal between the casing  142  and the port  215 . The seal formed between the pad  218  and the casing  142  can prevent or reduce any fluids within the casing from entering the downhole tool  200 . The pad  218  need not be rubber and may be constructed of any suitable material for forming a seal. In some cases, the pad  218  may be eliminated. 
     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  FIGS. 2 and 3 , the sealer  206  may include a sealant reservoir or tank  224  and conduit  207 . In one or more embodiments, the sealer  206  can introduce a sealant  221  via a conduit  207  to the hole formed by the bit  209  by flowing the sealant  221  to the hole along a surface portion of the bit  209 . The sealer  206  can introduce the sealant  221  using a pressurized sealant tank  224 , a pump, gravity, or any other suitable delivery system. 
     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. 
       FIG. 3  shows a non-limiting embodiment using a portion of the bit  209  and the sealant  221  as a sealing device to seal the hole formed by the bit  209 . The scoring member  212  can contact and score the bit  209  and the tool string  106  can be moved axially within the casing  142  to apply force to the scored bit  209 , thereby breaking the bit  209  and leaving a portion of the bit  209  within the hole formed by the bit  209 . The sealant introduced via conduit  207  can seal at least a portion of any gap between the bit and the hole formed by the bit  209  to isolate the formation from the interior of the casing  142 . For example, the sealant  221  can seal gaps around the bit  209  that may be formed by flutes, channels, grooves, or other surface irregularities on the bit  209  to provide a sealed hole that can reduce or prevent formation fluid and other contaminants within the formation  104  from entering the casing  142 . 
       FIG. 3  also illustrates the perforator  203  in a retracted position within the tool string  106  with the retained portion of the broken bit  209  deposited in a bit receptacle  303  and a new bit loaded into the perforator  203  from a bit cartridge  306 . In one or more embodiments, the bit cartridge  306  can hold one or more unbroken bits  209  for use by the perforator  203  in forming one or more additional holes into the formation  104 , as discussed above. Although not shown, the tool string  106  can include a mechanism, system, device, or combinations thereof that can seal the port  215  when a bit  209  is not disposed through the port  215 . The perforator  203  can rotate such that the bit cartridge  306  can advance a new bit  209  into the perforator  203 . Advancement of a new bit  209  into the perforator can push or otherwise eject any broken portion of a bit  209  into the bit receptacle  303 . With a new bit  209  inserted into the perforator  203 , the perforator can be used to form one or more additional holes through the casing  142 , cement  140 , and into the formation  104 , as discussed above. In one or more embodiments, the entire bit  209  may be used to seal the hole formed by the bit  209  and the bit receptacle  303  can be eliminated. In one or more embodiments, the sealant  221  may be introduced along a surface portion of the bit  209  to the hole formed by the bit  209  with the bit retracted for re-use and the bit cartridge can also be eliminated. 
       FIG. 4  is an elevation view of an illustrative non-limiting example of a downhole tool  400  according to one or more embodiments. The downhole tool  400  can include a perforator  203 , a sealer  206 , a port  215 , a scoring member  212 , a pad  218 , a bit receptacle  303 , and a bit cartridge  306 , which can be substantially similar as discussed and described above with reference to  FIGS. 1-3 . The exemplary downhole tool  400  as shown further comprises an extendable bit  209  that may be opposed by extendable feet  403 ,  404 . The bit  209  can be rotated and/or linearly moved via motor  418  and/or motor  415 . In one or more embodiments, the motor  418 , the motor  415 , or both can be hydraulic, pneumatic, and/or electromechanical motors. In one or more embodiments, the opposing feet  403 ,  404  can be extended and/or retracted via one or more hydraulic, pneumatic, and/or electro-mechanical motors  405 . In one or more embodiments, the downhole tool  400  can further include a downhole evaluation system  412  for evaluating one or more formation properties. In one or more embodiments, the downhole tool  400  can include a tool control unit  480  for operating, instructing, controlling, or otherwise directing one or more functions of the downhole tool  400 . In one or more embodiments, the sealer  206  and/or the downhole evaluation system  412  can be in fluid communication with a chamber  450 . 
     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  FIG. 3 , the perforator  206  can include a bit receptacle  303  and a bit cartridge  306  for receiving broken and/or used bits  209  from the perforator  406  and for supplying new bits  209  to the perforator  406 , respectively. In one or more embodiments, the bit cartridge  306  can advance a new bit to engage with the perforator  203  using any suitable mechanism, system, and/or device. For example, the bit cartridge  306  can advance a new bit using a telescoping platform operated via a motor  452  as shown, or other suitable mechanisms such as a spring or advancing track. Depending upon the particular configuration of the downhole tool  400 , the bit receptacle  303 , bit cartridge  306 , or both can be eliminated, as discussed and described above with reference to  FIG. 3 . 
     As discussed and described above with reference to  FIGS. 2 and 3 , the downhole tool  400  can include a sealer  206 . In one or more embodiments, the sealant  221  introduced to the hole formed by the bit  209 , can include one or more components, for example a two-part epoxy. For a multi-component sealant the sealer  206  can store a first part of the epoxy in a first reservoir or tank  460  and a second part of the epoxy in a second reservoir or tank  466 . Alternatively, as discussed above the sealant can be introduced from the surface via one or more conduits, through the casing via a pill, or any other suitable delivery method. The first part stored in the first tank  460  and the second part stored in the second tank  466  can be introduced to the chamber  450  via conduits  462  and  468 , respectively. One or more valves  464 ,  468  can be used to control the amount of sealant introduced from the sealer  206  to the chamber  450 . The first and second part can be mixed within the chamber  450 , within a common flow line or common mixing line, not shown, or both. 
     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 ,  452   405 , 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  FIG. 1 , which can provide instructions for operating the downhole tool  400 . In one or more embodiments, the electronics section  126  disposed on the tool string  106  can independently control operation of the downhole tool  400 . 
     In several non-limiting embodiments the downhole tools  136 ,  200 ,  300  and  400  described above and shown in  FIGS. 1-4  may include a sensor cartridge. In several non-limiting embodiments the downhole tools may be used to insert one or more sensors within the hole formed by the bit. The one or more sensors may be sealed within the hole using the sealant, at least a portion of the bit, or a combination thereof. The one or more sensors may monitor one or more formation properties. For example, the one or more sensors may monitor a formation pressure, which may be communicated via wireless communication to a receiver device. The receiver device may be conveyed into the borehole and positioned within a suitable range of a sensor for communication therebetween. In one or more embodiments, the receiver device may be disposed on the one or more downhole tools  136 ,  200 ,  300 ,  400  or any other suitable downhole tool. 
       FIGS. 5-7  depict illustrative bits  500 ,  600 ,  700  according one or more embodiments. The exemplary bits  500 ,  600 ,  700  may be any suitable bit for forming a hole in the sidewall of a borehole and/or a reinforced borehole into the formation  104 . The bits can include a cutting end  502 , a tool contact end  506  and an elongated shaft  510  disposed therebetween. In one or more embodiments, the cross-section of the bits can be uniform, for example a constant diameter or the cross-section can vary. In one or more embodiments, the bits can expand at the tool contact end  506  to provide bits having a larger cross-section at the tool contact end  506  than the cutting end  502  and/or shaft  506 . In at least one embodiment the bits can have a circular diameter with the tool contact end  506  expanding radially from a central axis. 
     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  FIGS. 2-4  may also include a tapered or pointed pin or rod that may be forced into a recess or hole disposed within the tool contact end  506  of the bit  209 . The force applied by the perforator  203 , the extendable feet  403 ,  404 , and/or other equipment can push or otherwise urge the tapered pin into the recess, which may expand the tool contact end  506 . 
     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  FIGS. 2 and 3  is introduced to a surface portion of the bit the one or more flutes can act as a guide in which the sealant can flow into the hole formed by the bit. 
     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  FIGS. 2-4 , which can rotate the bits. In one or more embodiments, the star shaped hole can be any suitably shaped hole, for example a triangle, square, pentagon, or any other polygonal shaped hole. In one or more embodiments, the hole or recess may be disposed on the perforator  203  with the complimentary shaped rod disposed on or about the contact end  506  of the bit. 
     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  FIG. 5 , the tool contact end  506  can include one or more surface modifications for holding or otherwise securing the bit  500  within the casing  142 , the cement  140 , and/or the formation  104 . As shown, the bit  500  includes a plurality of angularly oriented protrusions  515  adapted to engage with the casing  142 , cement  140 , and/or the formation  104  to secure and prevent the bit from coming out of the hole formed by the bit  500 . If sealant is also introduced to the hole formed by the bit  500 , the sealant can improve the sealing qualities provided by the bit  500 . 
     Referring to  FIG. 6 , the tool contact end  506  can include one or more surface modifications for holding or otherwise securing the bit  600  within the casing  142 , the cement  140 , and/or the formation  104 . As shown, the bit  600  includes a tool contact end  506  having threads  605 . The threads  605  can be self-tapping. The threads  605  can be oriented such that when urged into the hole formed by the bit  600 , the tool contact end  506  may be rotated to screw into and secure the bit  600  within the hole formed by the bit  600 . The threads  605  can be oriented, such that the bit  600  can be screwed into the casing  142 , cement  140 , and/or formation  104  clockwise or counterclockwise. The threads  605  can be “self-tapping” threads. 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   
     Referring to  FIG. 7 , the tool contact end  506  can include one or more surface modifications for holding or otherwise securing the bit  700  within the casing  142 , the cement  140 , and/or the formation  104 . As shown, the bit  700  includes a tool contact end  506  having one or more O-rings  705 . The O-rings  705  can exert an outward force that can engage the walls of the hole formed by the bit, thereby securing the bit  700  within the hole formed by the bit. 
     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. 
       FIG. 8  illustrates one example of a non-limiting method  800  according to the disclosure. The method  800  includes conveying a carrier into a borehole  802 . The carrier may include a downhole tool coupled to the carrier. The downhole tool may be substantially similar to the downhole tools  136 ,  200 ,  300 , and  400  described above and shown in  FIGS. 1-7 . That is the downhole tool includes a bit and a sealer. The method  800  may further include forming a hole in the sidewall of the borehole using the bit  804 . The method  800  also includes introducing a sealant to the hole along a surface portion of the bit using the sealer  806 . In one non-limiting embodiment the sealant may be introduced via a pill to the borehole, where the sealant may flow along a surface portion of the bit into the hole. The method  800  may optionally include rotating the bit as the sealant flows along a surface portion of the bit to improve introduction of the sealant to the hole formed by the bit. The method  800  may optionally include measuring at least one formation property through the hole before introducing the sealant to the hole. In one or more embodiments, the method  800  may include recovering one or more formation fluid samples through the hole before introducing the sealant to the hole. 
       FIG. 9  illustrates another example of a non-limiting method  900  according to the disclosure. The method  900  includes conveying a carrier into a borehole  902 . The carrier may include a downhole tool coupled to the carrier. The downhole tool may be substantially similar to the downhole tools  136 ,  200 , and  400  described above and shown in  FIGS. 1-7 . That is the downhole tool includes a bit and a sealer. The method  900  may further include forming a hole in the sidewall of the borehole using a bit  904 . The method  900  also includes sealing at least a portion of the hole formed by the bit by leaving at least a portion of the bit in the hole. In one non-limiting embodiment the entire bit may be used to seal at least a portion of the hole. In another non-limiting embodiment the bit may be scored by a scorer and the downhole tool may be moved axially to forcefully break the bit, thereby leaving a portion of the bit within the hole. The method  900  may optionally include measuring at least one formation property through the hole before introducing at least a portion of the bit into the hole to seal at least a portion of the hole. In one or more embodiments, the method  900  may include recovering one or more formation fluid samples through the hole before introducing at least a portion of the bit into the hole to seal at least a portion of the hole. 
     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&#39;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.