Methods of using a particle impact drilling system for removing near-borehole damage, milling objects in a wellbore, under reaming, coring, perforating, assisting annular flow, and associated methods

A particle impact drilling system and method are described. In several exemplary embodiments, the system and method may be a part of, and/or used with, an apparatus or system, methods, to excavate a subterranean formation. The system can including, for example, removing near-borehole damage, casing, window milling, fishing, drilling with casing, under reaming, coring, perforating, effective circulatory density management, assisted annular flow, and directional control. Embodiments of associated systems and methods are also included.

BACKGROUND

This disclosure generally relates to a system and method for injecting particles into a flow region in connection with, for example, excavating a formation. The formation may be excavated in order to, for example form a wellbore for the purpose of oil and gas recovery, construct a tunnel, or form other excavations in which the formation is cut, milled, pulverized, scraped, sheared, indented, and/or fractured, hereinafter referred to collectively as cutting.

SUMMARY OF THE INVENTION

Disclosed herein is a method of milling an object in a wellbore. In an embodiment the milling method includes providing in the wellbore a drill string and a drill bit with nozzles thereon that are in fluid communication with the drill string, flowing a mixture of impactors and pressurized circulating fluid within the drill string so that the impactors in the mixture exit the nozzles with sufficient energy to structurally alter the object when contacting the object, and eroding the object by directing at least one of the nozzles at the object while impactors exit the at least one nozzle so that the exiting impactors contact and structurally alter the object. Continuing eroding the object until the object is removed from the wellbore defines milling the object. The object can be casing lining the wellbore, a drill bit attached to casing used to bore the wellbore, or any other object in the wellbore. The bit can be rotated by ejecting pressurized fluid from a nozzle on the bit in a direction lateral to and offset from the bit axis. The drill bit can be replaced with a cutting member, where the cutting member can be a bit, a mill, a lead mill, a modified bit, or a modified mill.

Also disclosed is a wellbore under reamer apparatus having a drill string, a bit in fluid communication with the drill string, at least one nozzle in fluid communication with the drill string, a mixture of a pressurized circulating fluid and a plurality of impactors flowing in the drill string and exiting the nozzle, the nozzle exit directed lateral to the drill string so that when the drill string and nozzle is disposed in a wellbore that intersects a formation, the exiting impactors contact the formation with sufficient energy to structurally alter the formation and increase the wellbore diameter. A nozzle can be on the drill string, drill bit, or a nozzle can be on the string with an additional nozzle on the bit.

Additionally disclosed herein is a method of increasing the diameter of a borehole that intersects a formation. This method includes providing in the borehole a drill string and a nozzle that is in fluid communication with the drill string and flowing a mixture of impactors and pressurized circulating fluid through the drill string and to the nozzle so that the impactors exit the nozzle and contact the borehole circumference with sufficient energy to compress and structurally alter the formation thereby eroding formation at the borehole circumference to widen the borehole.

The present disclosure also includes a method of treating a circumference wall of a borehole. Treating can involve providing in the borehole a drill string and a nozzle that is in fluid communication with the drill string and selectively removing an identified portion of the borehole wall by flowing a mixture of impactors and pressurized circulating fluid through the drill string and to the nozzle so that the impactors exit the nozzle and contact the identified portion of the borehole wall with sufficient energy to compress and structurally alter the identified portion thereby eroding away the identified portion in the borehole. Filtercake and near wellbore formation damage can be removed with this method. Additionally, borehole wall permeability can be increased by removing the identified portion.

Described herein is a method of enhancing the flow of a drilling fluid in the annulus between a wellbore and a drill string. An embodiment of this method includes excavating a wellbore with a drilling system having a bit disposed on the end of a drill string and a nozzle, directing pressurized drilling fluid into the drill string to deliver to the drill bit, the pressurized drilling fluid being positioned to exit the system and flow up the wellbore, the nozzle being in fluid communication with the drill string and the pressurized drilling fluid, and selectively discharging pressurized drilling fluid from that nozzle into the annulus at localized lower pressure regions to perturb the regions and promote annular flow of drilling fluid along the wellbore. A nozzle can be on the drill string, drill bit, or a nozzle can be on the string with an additional nozzle on the bit.

The present disclosure further includes description of a device to retrieve core samples from a subterranean formation. The device can include an annular body, a nozzle, and a mixture of impactors and pressurized circulating fluid in selective fluid communication with the nozzle, so that flowing the mixture through the nozzle and directing the nozzle at the formation discharges impactors from the nozzle with sufficient energy to cut a core sample in the formation receivable in the annular body by compressing and structurally altering the formation. Additional nozzles can be included that are arranged to form a core sample insertable within the annular body.

A method of retrieving a core sample from a subterranean formation is described that includes providing an annular coring device and at least one nozzle in a wellbore that intersects the formation, discharging a mixture of impactors and pressurized circulating fluid from the nozzle to form a stream, directing the stream to the subterranean formation so that the impactors in the stream contact the formation with sufficient energy to compress and alter its structure thereby removing formation in a zone surrounding impactor contact, cutting a kerf in the formation with the stream thereby defining an outer peripheral surface of a core sample, and removing the core sample with the coring device. Coring can be on a wellbore sidewall or bottom hole.

Additionally described herein is a method of perforating a subterranean formation that includes providing a nozzle in a wellbore that intersects the formation, flowing a mixture of impactors and pressurized circulating fluid to the nozzle, discharging the mixture from the nozzle to form a stream, and directing the stream at the formation, so that the impactors in the stream contact the formation with sufficient energy to compress and alter its structure thereby removing formation to form a perforation in the formation. The nozzle can be relocated to other locations within the wellbore and additional perforations made at the other locations. A second nozzle can be included for perforating. The nozzle can be selectively extended into the formation thereby increasing the perforation depth.

DETAILED DESCRIPTION

In the drawings and description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawings are not necessarily to scale. Certain features of the disclosure may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present disclosure is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art upon reading the following detailed description of the embodiments and by referring to the accompanying drawings.

Particle Impact Drilling System and Delivery Overview

An overview of embodiments of a Particle Impact Drilling (PID) system and associated methods of delivery of particle impactors for use in subterranean excavation is shown inFIGS. 1-20and as will be described further herein. For example,FIGS. 1 and 2illustrate an embodiment of an excavation system1including the use of solid material particles, or impactors,100to engage and excavate a subterranean formation52to create a wellbore70. The excavation system1, for example, may include a pipe string55having a plurality of collars58, one or more pipes56, and a kelly50. An upper end of the kelly50may interconnect with a lower end of a swivel quill26as understood by those skilled in the art. An upper end of the swivel quill26may be rotatably interconnected with a swivel28. The swivel28may include a top drive assembly (not shown) to rotate the pipe string55. Alternatively, for example, the excavation system1may further include a body member, such as a drill bit60, to cut the formation52in cooperation with the solid material impactors100. The drill bit60may be attached to the lower end55B of the pipe string55and may engage a bottom surface66of the wellbore70. The drill bit60may be a roller cone bit, a fixed cutter bit, an impact bit, a spade bit, a mill, an impregnated bit, a natural diamond bit, or other suitable implement for cutting rock or earthen formation.

As illustrated inFIG. 1, the pipe string55may include a feed, or upper end55A located substantially near an excavation rig5and a lower end55B including a nozzle64supported thereon. The lower end55B of the string55may include the drill bit60supported thereon. The excavation system1is not limited to excavating a wellbore70. The excavation system and method may also be applicable to excavating a tunnel, a pipe chase, a mining operation, or other excavation operation so that earthen material or formation may be removed.

In another exemplary embodiment, the present system may be used to inject any solid particulate material into a wellbore. Exemplary particles may be magnetic or non-magnetic solid particles. Exemplary uses of the present system include, but are not limited to, casing exits.

To excavate the wellbore70, the swivel28, the swivel quill26, the kelly50, the pipe string55, and a portion of the drill bit60, if used, may each include an interior passage that allows circulation fluid to circulate through each of the aforementioned components. The circulation fluid may be withdrawn from a tank6, pumped by a pump2, through a through medium pressure capacity line8, through a medium pressure capacity flexible hose42, through a gooseneck36, through the swivel28, through the swivel quill26, through the kelly50, through the pipe string55, and through the bit60.

The excavation system1further has at least one nozzle64on the lower end55B of the pipe string55for accelerating one or more solid material impactors100as the impactors100exit the pipe string100. The nozzle64is designed to accommodate the impactors100, such as an especially hardened nozzle, a shaped nozzle, or an “impactor” nozzle, which may be particularly adapted to a particular application. The nozzle64may be a type that is known and commonly available. The nozzle64may further be selected to accommodate the impactors100in a selected size range or of a selected material composition. Nozzle size, type, material, and quantity may be a function of the formation being cut, fluid properties, impactor properties, and/or desired hydraulic energy expenditure at the nozzle64. If a drill bit60is used, the nozzle or nozzles64may be located in the drill bit60.

The nozzle64may alternatively be a conventional dual-discharge nozzle as understood by those skilled in the art. Such dual discharge nozzles may generate: (1) a radially outer circulation fluid jet substantially encircling a jet axis, and/or (2) an axial circulation fluid jet substantially aligned with and coaxial with the jet axis, with the dual discharge nozzle directing a majority by weight of the plurality of solid material impactors into the axial circulation fluid jet. A dual discharge nozzle64may separate a first portion of the circulation fluid flowing through the nozzle64into a first circulation fluid stream having a first circulation fluid exit nozzle velocity, and a second portion of the circulation fluid flowing through the nozzle64into a second circulation fluid stream having a second circulation fluid exit nozzle velocity lower than the first circulation fluid exit nozzle velocity. The plurality-of solid material impactors100may be directed into the first circulation fluid stream such that a velocity of the plurality of solid material impactors100while exiting the nozzle64is substantially greater than a velocity of the circulation fluid while passing through a nominal diameter flow path in the lower end55B of the pipe string55, to accelerate the solid material impactors100.

Each of the individual impactors100is structurally independent from the other impactors. For brevity, the plurality of solid material impactors100may be interchangeably referred to as simply the impactors100. The plurality of solid material impactors100may be substantially rounded and have either a substantially non-uniform outer diameter or a substantially uniform outer diameter. For example, the solid material impactors100may be substantially spherically shaped, non-hollow, and formed of rigid metallic material and the impactors100may have high compressive strength and crush resistance, such as steel shot, ceramics, depleted uranium, and multiple component materials. Although the solid material impactors100may be substantially a non-hollow sphere, alternative embodiments may provide for other types of solid material impactors, which may include impactors100with a hollow interior. The impactors may be magnetic or non-magnetic. The impactors may be substantially rigid and may possess relatively high compressive strength and resistance to crushing or deformation as compared to physical properties or rock properties of a particular formation or group of formations being penetrated by the wellbore70.

The impactors may be of a substantially uniform mass, grading, or size. The solid material impactors100may have any suitable density for use in the excavation system1. For example, the solid material impactors100may have an average density of at least 470 pounds per cubic foot.

Alternatively, the solid material impactors100may include other metallic materials, including tungsten carbide, copper, iron, or various combinations or alloys of these and other metallic compounds. The impactors100may also be composed of non-metallic materials, such as ceramics, or other man-made or substantially naturally occurring non-metallic materials. Also, the impactors100may be crystalline shaped, angular shaped, sub-angular shaped, selectively shaped, such as like a torpedo, dart, rectangular, or otherwise generally non-spherically shaped.

The impactors100may be selectively introduced into a fluid circulation system, such as illustrated inFIG. 1, near an excavation rig5, circulated with the circulation fluid (or “mud”), and accelerated through at least one nozzle64. “At the excavation rig” or “near an excavation rig” may also include substantially remote separation, such as a separation process that may be at least partially carried out on the sea floor.

Introducing the impactors100into the circulation fluid may be accomplished by any of several known techniques. For example, the impactors100may be provided in an impactor storage tank94near the rig5or in a storage bin82. A screw elevator14may then transfer a portion of the impactors at a selected rate from the storage tank94, into a slurrification tank98. A pump10, as understood by those skilled in the art, such as a progressive cavity pump, may transfer a selected portion of the circulation fluid from a mud tank6, into the slurrification tank98to be mixed with the impactors100in the tank98to form an impactor concentrated slurry. An impactor introducer96may be included to pump or introduce a plurality of solid material impactors100into the circulation fluid before circulating a plurality of impactors100and the circulation fluid to the nozzle64. The impactor introducer96, for example, may be a progressive cavity pump capable of pumping the impactor concentrated slurry at a selected rate and pressure through a slurry line88, through a slurry hose38, through an impactor slurry injector head34, and through an injector port30located on the gooseneck36, which may be located atop the swivel28. The swivel28, including the through bore for conducting circulation fluid therein, may be substantially supported on the feed, or upper, end of the pipe string55for conducting circulation fluid from the gooseneck36into the latter end55a. The upper end55A of the pipe string55may also include the kelly50to connect the pipe56with the swivel quill26and/or the swivel28. The circulation fluid may also be provided with rheological properties sufficient to adequately transport and/or suspend the plurality of solid material impactors100within the circulation fluid.

The solid material impactors100may also be introduced into the circulation fluid by withdrawing the plurality of solid material impactors100from a low pressure impactor source98into a high velocity stream of circulation fluid, such as by venturi effect. For example, when introducing impactors100into the circulation fluid, the rate of circulation fluid pumped by the mud pump2may be reduced to a rate lower than the mud pump2is capable of efficiently pumping. In such event, a lower volume mud pump4may pump the circulation fluid through a medium pressure capacity line24and through the medium pressure capacity flexible hose40.

The circulation fluid may be circulated from the fluid pump2and/or4, such as a positive displacement type fluid pump, through one or more fluid conduits8,24,40,42, into the pipe string55. The circulation fluid may then be circulated through the pipe string55and through the nozzle64. The circulation fluid may be pumped at a selected circulation rate and/or a selected pump pressure to achieve a desired impactor and/or fluid energy at the nozzle64.

The pump4may also serve as a supply pump to drive the introduction of the impactors100entrained within an impactor slurry, into the high pressure circulation fluid stream pumped by mud pumps2and4. Pump4may pump a percentage of the total rate of fluid being pumped by both pumps2and4, such that the circulation fluid pumped by pump4may create a venturi effect and/or vortex within the injector head34that inducts the impactor slurry being conducted through the line42, through the injector head34, and then into the high pressure circulation fluid stream.

From the swivel28, the slurry of circulation fluid and impactors may circulate through the interior passage in the pipe string55and through the nozzle64. As described above, the nozzle64may alternatively be at least partially located in the drill bit60. Each nozzle64may include a reduced inner diameter as compared to an inner diameter of the interior passage in the pipe string55immediately above the nozzle64. Thereby, each nozzle64may accelerate the velocity of the slurry as the slurry passes through the nozzle64. The nozzle64may also direct the slurry into engagement with a selected portion of the bottom surface66of wellbore70. The nozzle64may also be rotated relative to the formation52depending on the excavation parameters. To rotate the nozzle64, the entire pipe string55may be rotated or only the nozzle64on the end of the pipe string55may be rotated while the pipe string55is not rotated. Rotating the nozzle64may also include oscillating the nozzle64rotationally back and forth as well as vertically, and may further include rotating the nozzle64in discrete increments. The nozzle64may also be maintained rotationally substantially stationary.

The circulation fluid may be substantially continuously circulated during excavation operations to circulate at least some of the plurality of solid material impactors100and the formation cuttings away from the nozzle64. The impactors100and fluid circulated away from the nozzle64may be circulated substantially back to the excavation rig5, or circulated to a substantially intermediate position between the excavation rig5and the nozzle64.

If the drill bit60is used, the drill bit60may be rotated relative to the formation52and engaged therewith by axial force (WOB) acting at least partially along the wellbore axis75near the drill bit60. The bit60may also include a plurality of bit cones62, which also may rotate relative to the bit60to cause bit teeth secured to a respective cone to engage the formation52, which may generate formation cuttings substantially by crushing, cutting, or pulverizing a portion of the formation52. The bit60may also be formed of a fixed cutting structure that may be substantially continuously engaged with the formation52and create cuttings primarily by shearing and/or axial force concentration to fail the formation, or create cuttings from the formation52. To rotate the bit60, the entire pipe string55may be rotated or only the bit60on the end of the pipe string55may be rotated while the pipe string55is not rotated. Rotating the drill bit60may also include oscillating the drill bit60rotationally back and forth as well as vertically, and may further include rotating the drill bit60in discrete increments.

Also alternatively, the excavation system1may include a pump, such as a centrifugal pump, having a resilient lining that is compatible for pumping a solid material laden slurry. The pump may pressurize the slurry to a pressure greater than the selected mud pump pressure to pump the plurality of solid material impactors100into the circulation fluid. The impactors100may be introduced through an impactor injection port, such as port30. Other alternative embodiments for the system1may include an impactor injector for introducing the plurality of solid material impactors100into the circulation fluid.

As the slurry is pumped through the pipe string55and out the nozzles64, the impactors100may engage the formation with sufficient energy to enhance the rate of formation removal or penetration (ROP). The removed portions of the formation may be circulated from within the wellbore70near the nozzle64, and carried suspended in the fluid with at least a portion of the impactors100, through a wellbore annulus between the OD of the pipe string55and the ID of the wellbore70.

At the excavation rig5, the returning slurry of circulation fluid, formation fluids (if any), cuttings, and impactors100may be diverted at a nipple76, which may be positioned on a BOP stack74. The returning slurry may flow from the nipple76, into a return flow line15, which may include tubes48,45,16,12and flanges46,47. The return line15may include an impactor reclamation tube assembly44, as illustrated inFIG. 1, which may preliminarily separate a majority of the returning impactors100from the remaining components of the returning slurry to salvage the circulation fluid for recirculation into the present wellbore70or another wellbore. At least a portion of the impactors100may be separated from a portion of the cuttings by a series of screening devices, such as the vibrating classifiers84, as understood by those skilled in the art, to salvage a reusable portion of the impactors100for reuse to re-engage the formation52. A majority of the cuttings and a majority of non-reusable impactors100may also be discarded.

The reclamation tube assembly44may operate by rotating tube45relative to tube16. An electric motor assembly22may rotate tube44. The reclamation tube assembly44includes an enlarged tubular45section to reduce the return flow slurry velocity and allow the slurry to drop below a terminal velocity of the impactors100, such that the impactors100can no longer be suspended in the circulation fluid and may gravitate to a bottom portion of the tube45. This separation function may be enhanced by placement of magnets near and along a lower side of the tube45. The impactors100and some of the larger or heavier cuttings may be discharged through discharge port20. The separated and discharged impactors100and solids discharged through discharge port20may be gravitationally diverted into a vibrating classifier84or may be pumped into the classifier84. A pump (not shown) capable of handling impactors and solids, such as a progressive cavity pump may be situated in communication with the flow line discharge port20to conduct the separated impactors100selectively into the vibrating separator84or elsewhere in the circulation fluid circulation system.

In an exemplary embodiment, the return flow line15, which as noted previously may include tubes48,45,16,12and flanges46and47, may also include a vibrational source, such as for example, a variable amplitude, variable frequency vibrator. Exemplary vibrational devices include those produced by Eriez Magnetics, such as for example, a variable amplitude, variable frequency vibrator, although similar devices produced by other manufactures may also be used as understood by those skilled in the art. Employing such a vibrational device may help to prevent solid material impactors, drill cuttings and other particulate materials from forming “beaches” in the return flow line wherein solid masses of particulate material can form stagnate agglomerations. Additionally, the use of vibrational devices may also assist with the process of the return flow line carrying shot and drill cuttings from the annulus of the wellbore to the process equipment. In some exemplary embodiments, a plurality of vibrational devices may be employed in the return flow line(s) to prevent the accumulation of particles.

In another exemplary embodiment, movement of particles in the return flow line may be assisted by the addition of a lubricant. The lubricant can be water, oil, a polymer solution, or any other liquid lubricant, and can be dispersed from a source directly into the slurry flow of drilling fluids and solid material particles and/or particulate material. In an exemplary embodiment, the lubricant may be supplied to the slurry flow through a circumferential passage located, for example, at a flange connection, as described for example in U.S. Pat. No. 5,479,957, the disclosure of which is incorporated by reference in its entirety. An exemplary embodiment includes the Pipeline Lubrication System manufactured by Schwing Bioset, Inc. of Somerset, Wis. Injection of the lubricant can be done upstream of the wellbore, during the addition of the solid material impactors, or downstream of the wellbore, such as for example, in the return flow line. In certain embodiments, the lubricant may be directly added to the drilling fluids. In certain embodiments, the lubricant may be removed from the drilling fluids prior to the drilling fluids being recycled.

The vibrating classifier84may include a three-screen section classifier of which screen section18may remove the coarsest grade material. The removed coarsest grade material may be selectively directed by outlet78to one of storage bin82or pumped back into the flow line15downstream of discharge port20. A second screen section92may remove a re-usable grade of impactors100, which in turn may be directed by outlet90to the impactor storage tank94. A third screen section86may remove the finest grade material from the circulation fluid. The removed finest grade material may be selectively directed by outlet80to storage bin82, or pumped back into the flow line15at a point downstream of discharge port20. Circulation fluid collected in a lower portion of the classified84may be returned to a mud tank6for re-use.

The circulation fluid may be recovered for recirculation in a wellbore or the circulation fluid may be a fluid that is substantially not recovered. The circulation fluid may be a liquid, gas, foam, mist, or other substantially continuous or multiphase fluid. For recovery, the circulation fluid and other components entrained within the circulation fluid may be directed across a shale shaker (not shown) or into a mud tank6, whereby the circulation fluid may be further processed by techniques known in the art for re-circulation into a wellbore.

The excavation system1creates a mass-velocity relationship in a plurality of the solid material impactors100, such that an impactor100may have sufficient energy to structurally alter the formation52in a zone of a point of impact. The mass-velocity relationship may be satisfied as sufficient when a substantial portion by weight of the solid material impactors100may by virtue of their mass and velocity at the exit of the nozzle64, create a structural alteration as claimed or disclosed herein. Impactor velocity to achieve a desired effect upon a given formation may vary as a function of formation compressive strength, hardness, or other rock properties, and as a function of impactor size and circulation fluid rheological properties. A substantial portion means at least five percent by weight of the plurality of solid material impactors that are introduced into the circulation fluid.

The impactors100for a given velocity and mass of a substantial portion by weight of the impactors100are subject to the following mass-velocity relationship. The resulting kinetic energy of at least one impactor100exiting a nozzle64is at least 0.075 ft-lbs or has a minimum momentum of 0.0003 (ft-lbs.)/(sec).

Kinetic energy is quantified by the relationship of an object's mass and its velocity. The quantity of kinetic energy associated with an object is calculated by multiplying its mass times its velocity squared. To reach a minimum value of kinetic energy in the mass-velocity relationship as defined, small particles such as those found in abrasives and grits, must have a significantly high velocity due to the small mass of the particle. A large particle, however, needs only moderate velocity to reach an equivalent kinetic energy of the small particle because its mass may be several orders of magnitude larger.

The velocity of a substantial portion by weight of the plurality of solid material impactors100immediately exiting a nozzle64may be as slow as 100 feet per second and as fast as 1000 feet per second, immediately upon exiting the nozzle64.

The velocity of a majority by weight of the impactors100may be substantially the same, or only slightly reduced, at the point of impact of an impactor100at the formation surface66as compared to when leaving the nozzle64. Thus, it may be appreciated by those skilled in the art that due to the close proximity of a nozzle64to the formation being impacted, the velocity of a majority of impactors100exiting a nozzle64may be substantially the same as a velocity of an impactor100at a point of impact with the formation52. Therefore, in many practical applications, the above velocity values may be determined or measured at substantially any point along the path between near an exit end of a nozzle64and the point of impact, without material deviation from the scope of this disclosure.

In addition to the impactors100satisfying the mass-velocity relationship described above, a substantial portion by weight of the solid material impactors100have an average mean diameter of between approximately 0.050 to 0.500 of an inch.

To excavate a formation52, the excavation implement, such as a drill bit60or impactor100, must overcome minimum, in-situ stress levels or toughness of the formation52. These minimum stress levels are known to typically range from a few thousand pounds per square inch, to in excess of 65,000 pounds per square inch. To fracture, cut, or plastically deform a portion of formation52, force exerted on that portion of the formation52typically should exceed the minimum, in-situ stress threshold of the formation52. When an impactor100first initiates contact with a formation, the unit stress exerted upon the initial contact point may be much higher than 10,000 pounds per square inch, and may be well in excess of one million pounds per square inch. The stress applied to the formation52during contact is governed by the force the impactor100contacts the formation with and the area of contact of the impactor with the formation. The stress is the force divided by the area of contact. The force is governed by Impulse Momentum theory, as understood by those skilled in the art, whereby the time at which the contact occurs determines the magnitude of the force applied to the area of contact. In cases where the particle is contacting a relatively hard surface at an elevated velocity, the force of the particle when in contact with the surface is not constant, but is better described as a spike. The force, however, need not be limited to any specific amplitude or duration. The magnitude of the spike load can be very large and occur in just a small fraction of the total impact time. If the area of contact is small the unit stress can reach values many times in excess of the in situ failure stress of the rock, thus guaranteeing fracture initiation and propagation and structurally altering the formation52.

A substantial portion by weight of the solid material impactors100may apply at least 5000 pounds per square inch of unit stress to a formation52to create the structurally altered zone Z in the formation. The structurally altered zone Z is not limited to any specific shape or size, including depth or width. Further, a substantial portion by weight of the impactors100may apply in excess of 20,000 pounds per square inch of unit stress to the formation52to create the structurally altered zone Z in the formation. The mass-velocity relationship of a substantial portion by weight of the plurality of solid material impactors100may also provide at least 30,000 pounds per square inch of unit stress.

A substantial portion by weight of the solid material impactors100may have any appropriate velocity to satisfy the mass-velocity relationship. For example, a substantial portion by weight of the solid material impactors may have a velocity of at least 100 feet per second when exiting the nozzle64. A substantial portion by weight of the solid material impactors100may also have a velocity of at least 100 feet per second and as great as 1200 feet per second when exiting the nozzle64. A substantial portion by weight of the solid material impactors100may also have a velocity of at least 100 feet per second and as great as 750 feet per second when exiting the nozzle64. A substantial portion by weight of the solid material impactors100may also have a velocity of at least 350 feet per second and as great as 500 feet per second when exiting the nozzle64.

Impactors100may be selected based upon physical factors such as size, projected velocity, impactor strength, formation52properties and desired impactor concentration in the circulation fluid. Such factors may also include; (a) an expenditure of a selected range of hydraulic horsepower across the one or more nozzles, (b) a selected range of circulation fluid velocities exiting the one or more nozzles or impacting the formation, and (c) a selected range of solid material impactor velocities exiting the one or more nozzles or impacting the formation, (d) one or more rock properties of the formation being excavated, or (e), any combination thereof.

If an impactor100is of a specific shape such as that of a dart, a tapered conic, a rhombic, an octahedral, or similar oblong shape, a reduced impact area to impactor mass ratio may be achieved. The shape of a substantial portion by weight of the impactors100may be altered, so long as the mass-velocity relationship remains sufficient to create a claimed structural alteration in the formation and an impactor100does not have any one length or diameter dimension greater than approximately 0.100 inches. Thereby, a velocity required to achieve a specific structural alteration may be reduced as compared to achieving a similar structural alteration by impactor shapes having a higher impact area to mass ratio. Shaped impactors100may be formed to substantially align themselves along a flow path, which may reduce variations in the angle of incidence between the impactor100and the formation52. Such impactor shapes may also reduce impactor contact with the flow structures such those in the pipe string55and the excavation rig5and may thereby minimize abrasive erosion of flow conduits.

As illustrated inFIGS. 1-4, for example, a substantial portion by weight of the impactors100may engage the formation52with sufficient energy to enhance creation of a wellbore70through the formation52by any or a combination of different impact mechanisms. First, an impactor100may directly remove a larger portion of the formation52than may be removed by abrasive-type particles. In another mechanism, an impactor100may penetrate into the formation52without removing formation material from the formation52. A plurality of such formation penetrations, such as near and along an outer perimeter of the wellbore70may relieve a portion of the stresses on a portion of formation being excavated, which may thereby enhance the excavation action of other impactors100or the drill bit60. Third, an impactor100may alter one or more physical properties of the formation52. Such physical alterations may include creation of micro-fractures and increased brittleness in a portion of the formation52, which may thereby enhance effectiveness of the impactors100in excavating the formation52. The constant scouring of the bottom of the borehole also prevents the build up of dynamic filtercake, which can significantly increase the apparent toughness of the formation52.

FIG. 2illustrates an impactor100that has been impaled into a formation52, such as a lower surface66in a wellbore70. For illustration purposes, the surface66is illustrated as substantially planar and transverse to the direction of impactor travel T. The impactors100circulated through a nozzle64may engage the formation52with sufficient energy to affect one or more properties of the formation52.

A portion of the formation52ahead of the impactor100substantially in the direction of impactor travel T may be altered such as by micro-fracturing and/or thermal alteration due to the impact energy. In such occurrence, the structurally altered zone Z may include an altered zone depth D. An example of a structurally altered zone Z is a compressive zone Z1, which may be a zone in the formation52compressed by the impactor100. The compressive zone Z1may have a length L1, but is not limited to any specific shape or size. The compressive zone Z1may be thermally altered due to impact energy.

An additional example of a structurally altered zone102near a point of impaction may be a zone of micro-fractures Z2. The structurally altered zone Z may be broken or otherwise altered due to the impactor100and/or a drill bit60, such as by crushing, fracturing, or micro-fracturing.

FIG. 2also illustrates an impactor100implanted into a formation52and having created an excavation E wherein material has been ejected from or crushed beneath the impactor100. Thereby the excavation E may be created, which as illustrated inFIG. 3may generally conform to the shape of the impactor100.

FIGS. 3 and 4illustrate excavations E where the size of the excavation may be larger than the size of the impactor100. InFIG. 2, the impactor100is shown as impacted into the formation52yielding an excavation depth D.

An additional theory for impaction mechanics in cutting a formation52may postulate that certain formations52may be highly fractured or broken up by impactor energy.FIG. 4illustrates an interaction between an impactor100and a formation52. A plurality of fractures F and micro-fractures MF may be created in the formation52by impact energy.

An impactor100may penetrate a small distance into the formation52and cause the displaced or structurally altered formation52to “splay out” or be reduced to small enough particles for the particles to be removed or washed away by hydraulic action. Hydraulic particle removal may depend at least partially upon available hydraulic horsepower and at least partially upon particle wet-ability and viscosity. Such formation deformation may be a basis for fatigue failure of a portion of the formation by “impactor contact,” as the plurality of solid material impactors100may displace formation material back and forth.

Each nozzle64may be selected to provide a desired circulation fluid circulation rate, hydraulic horsepower substantially at the nozzle64, and/or impactor energy or velocity when exiting the nozzle64. Each nozzle64may be selected as a function of at least one of (a) an expenditure of a selected range of hydraulic horsepower across the one or more nozzles64, (b) a selected range of circulation fluid velocities exiting the one or more nozzles64, and (c) a selected range of solid material impactor100velocities exiting the one or more nozzles64.

To optimize rate of penetration (ROP), it may be desirable to determine, such as by monitoring, observing, calculating, knowing, or assuming one or more excavation parameters such that adjustments may be made in one or more controllable variables as a function of the determined or monitored excavation parameter. The one or more excavation parameters may be selected from a group including: (a) a rate of penetration into the formation52, (b) a depth of penetration into the formation52, (c) a formation excavation factor, and (d) the number of solid material impactors100introduced into the circulation fluid per unit of time. Monitoring or observing may include monitoring or observing one or more excavation parameters of a group of excavation parameters including: (a) rate of nozzle rotation, (b) rate of penetration into the formation52, (c) depth of penetration into the formation52, (d) formation excavation factor, (e) axial force applied to the drill bit60, (f) rotational force applied to the bit60, (g) the selected circulation rate, (h) the selected pump pressure, and/or (i) wellbore fluid dynamics, including pore pressure.

One or more controllable variables or parameters may be altered, including at least one of: (a) rate of impactor100introduction into the circulation fluid, (b) impactor100size, (c) impactor100velocity, (d) drill bit nozzle64selection, (e) the selected circulation rate of the circulation fluid, (f) the selected pump pressure, and (g) any of the monitored excavation parameters.

To alter the rate of impactors100engaging the formation52, the rate of impactor100introduction into the circulation fluid may be altered. The circulation fluid circulation rate may also be altered independent from the rate of impactor100introduction. Thereby, the concentration of impactors100in the circulation fluid may be adjusted separate from the fluid circulation rate. Introducing a plurality of solid material impactors100into the circulation fluid may be a function of impactor100size, circulation fluid rate, nozzle rotational speed, wellbore70size, and a selected impactor100engagement rate with the formation52. The impactors100may also be introduced into the circulation fluid intermittently during the excavation operation. The rate of impactor100introduction relative to the rate of circulation fluid circulation may also be adjusted or interrupted as desired.

The plurality of solid material impactors100may be introduced into the circulation fluid at a selected introduction rate and/or concentration to circulate the plurality of solid material impactors100with the circulation fluid through the nozzle64. The selected circulation rate and/or pump pressure, and nozzle selection may be sufficient to expend a desired portion of energy or hydraulic horsepower in each of the circulation fluid and the impactors100.

An example of an operative excavation system1may include a bit60with an 8½″ inch bit diameter. The solid material impactors100may be introduced into the circulation fluid at a rate of 12 gallons per minute. The circulation fluid containing the solid material impactors may be circulated through the bit60at orate of 462 gallons per minute. A substantial portion by weight of the solid material impactors may have an average mean diameter of 0.100″. The following parameters will result in a penetration rate of approximately 27 feet per hour into Sierra White Granite. In this example, the excavation system may produce 1413 solid material impactors100per cubic inch with approximately 3.9 million impacts per minute against the formation52. On average, 0.00007822 cubic inches of the formation52are removed per impactor100impact. The resulting exit velocity of a substantial portion of the impactors100from each of the nozzles64would average 495.5 feet per second. The kinetic energy of a substantial portion by weight of the solid material impacts100would be approximately 1.14 ft-lbs., thus satisfying the mass-velocity relationship described above.

Another example of an operative excavation system1may include a bit60with an 8½ inch bit diameter. The solid material impactors100may be introduced into the circulation fluid at a rate of 12 gallons per minute. The circulation fluid containing the solid material impactors may be circulated through the nozzle64at a rate of 462 gallons per minute. A substantial portion by weight of the solid material impactors may have an average mean diameter of 0.075″. The following parameters will result in approximately a 35 feet per hour penetration rate into Sierra White Granite. In this example, the excavation system1may produce 3350 solid material impactors100per cubic inch with approximately 9.3 million impacts per minute against the formation52. On average, 0.0000428 cubic inches of the formation52are removed per impactor100impact. The resulting exit velocity of a substantial portion of the impactors100from each of the nozzles64would average 495.5 feet per second. The kinetic energy of a substantial portion by weight of the solid material impacts100would be approximately 0.240 Ft Lbs., thus satisfying the mass-velocity relationship described above.

In addition to impacting the formation with the impactors100, the bit60may be rotated while circulating the circulation fluid and engaging the plurality of solid material impactors100substantially continuously or selectively intermittently. The nozzle64may also be oriented to cause the solid material impactors100to engage the formation52with a radially outer portion of the bottom hole surface66. Thereby, as the drill bit60is rotated, the impactors100, in the bottom hole surface66ahead of the bit60, may create one or more circumferential kerfs. The drill bit60may thereby generate formation cuttings more efficiently due to reduced stress in the surface66being excavated, due to the one or more substantially circumferential kerfs in the surface66.

The excavation system1may also include inputting pulses of energy in the fluid system sufficient to impart a portion of the input energy in an impactor100. The impactor100may thereby engage the formation52with sufficient energy to achieve a structurally altered zone Z. Pulsing of the pressure of the circulation fluid in the pipe string55, near the nozzle64also may enhance the ability of the circulation fluid to generate cuttings subsequent to impactor100engagement with the formation52.

Each combination of formation type, bore hole size, bore hole depth, available weight on bit, bit rotational speed, pump rate, hydrostatic balance, circulation fluid rheology, bit type, and tooth/cutter dimensions may create many combinations of optimum impactor presence or concentration, and impactor energy requirements. The methods and systems of this disclosure facilitate adjusting impactor size, mass, introduction rate, circulation fluid rate and/or pump pressure, and other adjustable or controllable variables to determine and maintain an optimum combination of variables. The methods and systems of this disclosure also may be coupled with select bit nozzles, downhole tools, and fluid circulating and processing equipment to effect many variations in which to optimize rate of penetration.

FIG. 5shows an alternate embodiment of the drill bit60(FIG. 1) and is referred to, in general, by the reference numeral110and which is located at the bottom of a well bore120and attached to a drill string130. The drill bit110acts upon a bottom surface122of the well bore120. The drill string130has a central passage132that supplies drilling fluids to the drill bit110as shown by the arrow A1. The drill bit110uses the drilling fluids and solid material impactors100when acting upon the bottom surface122of the well bore120. The drilling fluids then exit the well bore120through a well bore annulus124between the drill string130and the inner wall126of the well bore120. Particles of the bottom surface122removed by the drill bit110exit the well bore120with the drilling fluid through the well bore annulus124as shown by the arrow A2. The drill bit110creates a rock ring142at the bottom surface122of the well bore120.

FIG. 6illustrates a rock ring124formed by the drill bit110. An excavated interior cavity144is worn away by an interior portion of the drill bit110and the exterior cavity146and inner wall126of the well bore120are worn away by an exterior portion of the drill bit110. The rock ring142possesses hoop strength, which holds the rock ring142together and resists breakage The hoop strength of the rock ring142is typically much less than the strength of the bottom surface122or the inner wall126of the well bore120, thereby making the drilling of the bottom surface122less demanding on the drill bit110. By applying a compressive load and aside load, shown with arrows141, on the rock ring142, the drill bit110causes the rock ring142to fracture. The drilling fluid140then washes the residual pieces of the rock ring142back up to the surface through the well bore annulus124.

The mechanical cutters, utilized on many of the surfaces of the drill bit110, may be any type of protrusion or surface used to abrade the rock formation by contact of the mechanical cutters with the rock formation. The mechanical cutters may be Polycrystalline Diamond Coated (PDC), or any other suitable type mechanical cutter such as tungsten carbide cutters. The mechanical cutters may be formed in a variety of shapes, for example, hemispherically shaped, cone shaped, etc. Several sizes of mechanical cutters are also available, depending on the size of drill bit used and the hardness of the rock formation being cut.

FIG. 7illustrates drill bit110ofFIG. 5and includes two side nozzles200A,200B and a center nozzle202. The side and center nozzles200A,200B,202discharge drilling fluid and solid material impactors (not shown) into the rock formation or other surface being excavated. The solid material impactors may include steel shot ranging in diameter from about 0.010 inches to about 0.500 inches. However, various diameters and materials such as ceramics, etc. may be utilized in combination with the drill bit120. The solid material impactors contact the bottom surface122of the well bore120and are circulated through the annulus124to the surface. The solid material impactors may also make up any suitable percentage of the drilling fluid for drilling through a particular formation.

The center nozzle202(seeFIGS. 7 and 15) is located in a center portion203of the drill bit110. The center nozzle202may be angled to the longitudinal axis of the drill bit110to create an excavated interior cavity244and also cause the rebounding solid material impactors to flow into the major junk slot, or passage,204A. The side nozzle200A located on a side arm214A of the drill bit110may also be oriented to allow the solid material impactors to contact the bottom surface122of the well bore120and then rebound into the major junk slot, or passage,204A. The second side nozzle200B is located on a second side arm214B. The second side nozzle200B may be oriented to allow the solid material impactors to contact the bottom surface122of the well bore120and then rebound into a minor junk slot, or passage,204B. The orientation of the side nozzles200A,200B may be used to facilitate the drilling of the large exterior cavity46. The side nozzles200A,200B may be oriented to cut different portions of the bottom surface122. For example, the side nozzle200B may be angled to cut the outer portion of the excavated exterior cavity146and the side nozzle200A may be angled to cut the inner portion of the excavated exterior cavity146. The major and minor junk slots, or passages,204A,204B allow the solid material impactors, cuttings, and drilling fluid240to flow up through the well bore annulus124back to the surface. The major and minor junk slots, or passages,204A,204B are oriented to allow the solid material impactors and cuttings to freely flow from the bottom surface122to the annulus124.

As described earlier, the drill bit110may also include mechanical cutters and gauge cutters. Various mechanical cutters are shown along the surface of the drill bit110. Hemispherical PDC cutters are interspersed along the bottom face and the side walls of the drill bit110. These hemispherical cutters along the bottom face break down the large portions of the rock ring142and also abrade the bottom surface122of the well bore120. Another type of mechanical cutter along the side arms214A,214B is a gauge cutter230. The gauge cutters230form the final diameter of the well bore120. The gauge cutters230trim a small portion of the well bore120not removed by other means. Gauge bearing surfaces206are interspersed throughout the side walls of the drill bit110. The gauge bearing surfaces206ride in the well bore120already trimmed by the gauge cutters230. The gauge bearing surfaces206may also stabilize the drill bit110within the well bore120and aid in preventing vibration.

The center portion203(see, e.g.,FIG. 7) includes a breaker surface, located near the center nozzle202, includes mechanical cutters208for loading the rock ring142. The mechanical cutters208abrade and deliver load to the lower stress rock ring142. The mechanical cutters208may include PDC cutters, or any other suitable mechanical cutters. The breaker surface is a conical surface that creates the compressive and side loads for fracturing the rock ring142. The breaker surface and the mechanical cutters208apply force against the inner boundary of the rock ring142and fracture the rock ring142. Once fractured, the pieces of the rock ring142are circulated to the surface through the major and minor junk slots, or passages,204A,204B.

FIG. 8illustrates a drill bit110having the gauge bearing surfaces206and mechanical cutters208being interspersed on the outer side walls of the drill bit110. The mechanical cutters208along the side walls may also aid in the process of creating drill bit110stability and also may perform the function of the gauge bearing surfaces206if they fail. The mechanical cutters208are oriented in various directions to reduce the wear of the gauge bearing surface206and also maintain the correct well bore120diameter. As noted with the mechanical cutters208of the breaker surface, the solid material impactors fracture the bottom surface122of the well bore120and, as such, the mechanical cutters208remove remaining ridges of rock and assist in the cutting of the bottom hole. However, the drill bit110need not necessarily have the mechanical cutters208on the side wall of the drill bit110.

FIG. 9illustrates the drill bit110having the gauge cutters230included along the side arms214A,214B of the drill bit110. The gauge cutters230are oriented so that a cutting face of the gauge cutter230contacts the inner wall126of the well bore120. The gauge cutters230may contact the inner wall126of the well bore at any suitable backrake, for example, a backrake of about 15° to about 45°. Typically, the outer edge of the cutting face scrapes along the inner wall126to refine the diameter of the well bore120.

One side nozzle200A (FIG. 9) is disposed on an interior portion of the side arm214A and the second side nozzle200B is disposed on an exterior portion of the opposite side arm214B. Although the side nozzles200A,200B are shown located on separate side arms214A,214B of the drill bit110, the side nozzles200A,200B may also be disposed on the same side arm214A or214B. Also, there may only be one side nozzle,200A or200B. Also, there may only be one side arm,214A or214B.

Each side arm214A,214B fits in the excavated exterior cavity146formed by the side nozzles200A,200B and the mechanical cutters208on the face212of each side arm214A,214B. The solid material impactors from one side nozzle200A rebound from the rock formation and combine with the drilling fluid and cuttings flow to the major junk slot204A and up to the annulus124. The flow of the solid material impactors, shown by arrows205, from the center nozzle202also rebound from the rock formation up through the major junk slot204A.

Minor junk slot204B, breaker surface, and the second side nozzle200B are shown in greater detail inFIGS. 10 and 11. The breaker surface is conically shaped, tapering to the center nozzle202. The second side nozzle200B is oriented at an angle to allow the outer portion of the excavated exterior cavity146to be contacted with solid material impactors. The solid material impactors then rebound up through the minor junk slot204B, shown by arrows205, along with any cuttings and drilling fluid240associated therewith.

FIGS. 12 and 13illustrate a drill bit110having each nozzle200A,200B,202positioned to receive drilling fluid240and solid material impactors from a common plenum feeding separate cavities250,251, and252. Because the common plenum has a diameter, or cross section, greater than the diameter of each cavity250,251, and252, the mixture, or suspension of drilling fluid and impactors is accelerated as it passes from the plenum to each cavity. The center cavity250feeds a suspension of drilling fluid240and solid material impactors to the center nozzle202for contact with the rock formation. The side cavities251,252are formed in the interior of the side arms214A,214B of the drill bit110, respectively. The side cavities251,252provide drilling fluid240and solid material impactors to the side nozzles200A,200B for contact with the rock formation. By utilizing separate cavities250,251,252for each nozzle202,200A,200B, the percentages of solid material impactors in the drilling fluid240and the hydraulic pressure delivered through the nozzles200A,200B,202can be specifically tailored for each nozzle200A,200B,202. Solid material impactor distribution can also be adjusted by changing the nozzle diameters of the side and center nozzles200A,200B, and202by changing the diameters of the nozzles. In alternate embodiments, however, other arrangements of the cavities250,251,252, or the utilization of a single cavity, are possible.

FIG. 14illustrates the drill bit110in engagement with the rock formation270. As previously discussed, the solid material impactors272flow from the nozzles200A,200B,202and make contact with the rock formation270to create the rock ring142between the side arms214A,214B of the drill bit110and the center nozzle202of the drill bit110. The solid material impactors272from the center nozzle202create the excavated interior cavity244while the side nozzles200A,200B create the excavated exterior cavity146to form the outer boundary of the rock ring142. The gauge cutters230refine the more crude well bore120cut by the solid material impactors272into a well bore120with a smoother inner wall126of the correct diameter.

The solid material impactors272(FIG. 14) flow from the first side nozzle200A between the outer surface of the rock ring142and the interior wall216in order to move up through the major junk slot204A to the surface. The second side nozzle200B (not shown) emits solid material impactors272that rebound toward the outer surface of the rock ring142and to the minor junk slot204B (not shown). The solid material impactors272from the side nozzles200A,200B may contact the outer surface of the rock ring142causing abrasion to further weaken the stability of the rock ring142. Recesses274around the breaker surface of the drill bit110may provide a void to allow the broken portions of the rock ring142to flow from the bottom surface122of the well bore120to the major or minor junk slot204A,204B.

FIG. 15illustrates an example orientation of the nozzles200A,2000202. The center nozzle202is disposed left of the center line of the drill bit110and angled on the order of around 20° left of vertical. Alternatively, both of the side nozzles200A,200B may be disposed on the same side arm214of the drill bit110as shown inFIG. 15. In this embodiment, the first side nozzle200A, oriented to cut the inner portion of the excavated exterior cavity146, is angled on the order of around 10° left of vertical. The second side nozzle200B is oriented at an angle on the order of around 14° right of vertical. This particular orientation of the nozzles allows for a large interior excavated cavity244to be created by the center nozzle202. The side nozzles200A,200B create a large enough excavated exterior cavity146in order to allow the side arms214A,214B to fit in the excavated exterior cavity146without incurring a substantial amount of resistance from uncut portions of the rock formation270. By varying the orientation of the center nozzle202, the excavated interior cavity244may be substantially larger or smaller than the excavated interior cavity244illustrated inFIG. 14. The side nozzles200A,200B may be varied in orientation in order to create a larger excavated exterior cavity146, thereby decreasing the size of the rock ring142and increasing the amount of mechanical cutting required to drill through the bottom surface122of the well bore120. Alternatively, the side nozzles200A,200B may be oriented to decrease the amount of the inner wall126contacted by the solid material impactors272. By orienting the side nozzles200A,200B at, for example, a vertical orientation, only a center portion of the excavated exterior cavity146would be cut by the solid material impactors and the mechanical cutters would then be required to cut a large portion of the inner wall126of the well bore120.

The bottom surface122of the well bore120drilled by the drill bit110are shown inFIGS. 16-17. With the center nozzle angled on the order of around 20° left of vertical and the side nozzles200A,200B angled on the order of around 10° left of vertical and around 14° right of vertical, respectively, the rock ring142is formed. By increasing the angle of the side nozzle200A,200B orientation, an alternate rock ring142shape and bottom surface122is cut as shown inFIG. 17. The excavated interior cavity244and rock ring142are much more shallow as compared with the rock ring142inFIG. 16. It is understood that various different bottom hole patterns can be generated by different nozzle configurations.

Although the drill bit110is described comprising orientations of nozzles and mechanical cutters, any orientation of either nozzles, mechanical cutters, or both may be utilized. The drill bit110need not have a center portion203. The drill bit110also need not even create the rock ring142. For example, the drill bit may only have a single nozzle and a single junk slot. Furthermore, although the description of the drill bit110describes types and orientations of mechanical cutters, the mechanical cutters may be formed of a variety of substances, and formed in a variety of shapes.

FIGS. 18-19illustrate a drill bit150in accordance with a second embodiment of the present invention. As previously noted, the mechanical cutters, such as the gauge cutters230, mechanical cutters208, and gauge bearing surfaces206may not be necessary in conjunction with the nozzles200A,200B,202in order to drill the required well bore120. The side wall of the drill bit150may or may not be interspersed with mechanical cutters. The side nozzles200A,200B and the center nozzle202are oriented in the same manner as in the drill bit150, however, the face212of the side arms214A,214B includes angled (PDCs)280as the mechanical cutters.

InFIGS. 18-20, for example, each row of PDCs280is angled to cut a specific area of the bottom surface122of the well bore120. A first row of PDCs280A is oriented to cut the bottom surface122and also cut the inner wall126of the well bore120to the proper diameter. A groove282is disposed between the cutting faces of the PDCs280and the face212of the drill bit150. The grooves282receive cuttings, drilling fluid240, and solid material impactors and direct them toward the center nozzle202to flow through the major and minor junk slots, or passages,204A,204B toward the surface. The grooves282may also direct some cuttings, drilling fluid240, and solid material impactors toward the inner wall126to be received by the annulus124and also flow to the surface. Each subsequent row of PDCs280B,280C may be oriented in the same or different position than the first row of PDCs280A. For example, the subsequent rows of PDCs280B,280C may be oriented to cut the exterior face of the rock ring142as opposed to the inner wall126of the well bore120. The grooves282on one side arm214A may also be oriented to direct the cuttings and drilling fluid240toward the center nozzle202and to the annulus124via the major junk slot204A. The second side arm214B may have grooves282oriented to direct the cuttings and drilling fluid240to the inner wall126of the well bore120and to the annulus124via the minor junk slot204B.

The PDCs280located on the face212of each side arm214A,214B are sufficient to cut the inner wall126to the correct size. Mechanical cutters, however, may be placed throughout the side wall of the drill bit150to further enhance the stabilization and cutting ability of the drill bit150.

Additional downhole applications are provided below; they include Downhole Milling, Under Reaming, Removing Near Borehole Damage, Assisted Annular Flow, Coring, and Perforating. Each of these applications include directing impactors in a circulation fluid, as described above, for downhole excavating purposes. The fluid may comprise wellbore fluid, drilling fluid, foam, a substance acting as a fluid, a substance having a fluid phase, a substance acting as an impactor carrier, and any medium for conveying impactors. The impactors may be fully or partially recovered for later use, or may be fully or partially abandoned in the wellbore or elsewhere. The impactor speed may range from around 100 feet/second to around 1000 feet/second and all ranges of values therebetween. Other impactor speeds include around 350 feet/second, 400, feet/second, 450 feet/second, 500 feet/second, 550 feet/second and above. The speed may either be at nozzle exit or upon collision of the impactor with what is being excavated.

Casing and window milling are performed for a variety of purposes. The basic concept for milling a window is to create an opening in a cased hole which connects the bore hole with a downhole formation. Some of the purposes are, but not limited, to create an opening in casing which allows directional drilling away from the borehole and casing, to create an opening in casing to provide means to horizontally drill boreholes away from the cased borehole, to create an opening through casing to allow drilling around debris that cannot be or economically retrieved in a borehole, and create openings that allow formation information to be gathered by a variety of tools and probes.

Traditionally these openings are created by forcing a drill head to be rotated by a drill string, downhole motor, or downhole turbine. Tools are set in the casing at the location where the window (opening) in the casing will be created. One of the most common types of tools used is referred to a whipstock. The tool consists of anchors to make it immobile in the casing and a concaved tapered section which starts at a full diameter of the internal casing diameter and tapers across the whole diameter of the interior of the casing. A cutting head is both rotated and advanced against the whipstock. As the cutting head is advanced, the taper forces the cutting structure of the cutting head against the interior wall of the casing. As the cutting head continues to advance downhole, it progressively cuts the casing and eventually cuts completely through the casing or multiple casings essentially concentric to each other, and enters the formation drilling an angled hole the diameter of the cutting head.

The cutting heads usually include conventional drill bits, or specially fabricated cutting heads having tungsten carbide shards or pieces attached to a thread bearing body. Conventional bits such as rolling cone bits, natural diamond bits, synthetic diamond bits, and impregnated diamond bits can be used to create these openings in the casing. A window can also be created using a downhole motor and bent subs. A downhole motor is attached to a bent sub in the lower portion of the drill string. The bent sub assembly is positioned in the direction that the casing opening will be formed. The drill string is not rotated but the downhole motor or turbine rotates the cutting head or bit. Using whipstock types of tools or plugs, the assembly is advanced by adding weight to the cutting assembly via the drill string. The downhole motor and bit combination will eventually cut through the casing and into the formation in the direction and angle from vertical as planned.

Horizontal drilling is accomplished in much the same way. The main difference is in the size and departure angle from the cased borehole to create a short radius turn into the formation. Once the short radius borehole is cut through the casing and reaches near horizontal, the borehole is drilled horizontally to engage more producing surface area in the producing formation. The issue in opening these casing windows is the time it takes to cut through the steel casing. Conventional bits and cutting heads will have only a small portion of their cutting structures engaged in cutting the casing from the start and through a significant part of cutting the window. Because of the small number of cutters attacking the casing when cutting is being done early in the process, very light weights on bit are used as not to damage the cutting structure of the bit and rendering the bit damaged before the opening is completely cut. Not only is the cutting structure in danger of damage, but cutting steel compared to rock is much harder for conventional bits. Carbide bearing milling tools are somewhat better but still slow and cannot drill into the formation as far as needed after the milled window has been cut economically. Diamond does not do well in the presence of iron and degrades when temperatures are elevated at the cutting edge of the diamond.

As discussed above, PID technology has demonstrated it can excavate through hard formations at 3-5 times the rate of conventional drill bit systems. Laboratory tests indicate a PID system can penetrate metals and metal composites at higher rates as well. As described above and in the referenced patents and patent applications, the PID system includes an injections means that deposits a small volume percent of the total downhole fluid flow with particles (impactors). The impactors are transported to the bit or cutting head where the impactors are accelerated through nozzles to velocities sufficient to deliver the energy required to fail and erode an impacted surface. The conventional fluid flow rate for oil and gas excavating operations imparts several million impacts per minute onto the excavation surface. After impact the impactors migrate to the surface for recovery and reinjection into the pressurized circulating fluid stream downhole.

A particle impact drilling system can be used for milling an object in a wellbore. In an embodiment of this method, illustrated in flow chart ofFIG. 29, includes providing a particle impact drilling system having a bit2017disposed on a drill string2015(step100). The drill string2015as shown is configured to convey impactors in a circulating fluid under pressure to the bit2017. A nozzle2021is positioned on the bit2017and is in fluid communication with the drill string2015. The nozzle2021is configured to eject the impactors at a velocity so the impactors have sufficient energy they compress, fracture, and structurally alter material within the wellbore.

One method of use, involves inserting the bit2017into a wellbore2003(step102) and directing the bit2017adjacent the object within the wellbore2003(step104). A plurality of impactors is then ejected from the bit2017when the bit2017is in milling contact with the object (step106). Then the bit2017is urged toward and, in some circumstances through the object, while the impactors are ejected at the object and collide with the object. As discussed above, the impactors' collisions fracture the object thereby eroding it. Continued contact with colliding impactors removes the object by reducing it to cuttings that are washed away by circulating fluid, or forms an opening through the object; this is referred to herein as impact milling of the object. The object being milled or eroded, for example, includes casing2007which lines the wellbore2003, a downhole tool lodged in the wellbore2003, or a drilling bit2043used in forming a wellbore2041from a drilling with casing excavation operation. For the purposes of discussion herein, milling contact occurs when the bit2017is sufficiently proximate an object such that impactors ejected from the bit2017impact the object with a velocity so the impactors possess sufficient energy to erode away portions of the object by contact, thereby milling the object. In some situations this includes cutting through the object (such as in window milling). Milling contact also includes physical contact between the bit2017and the object that may occur when milling the object with the bit2017.

It should be pointed out that the bit2017described herein is not limited to traditional drilling bits that drill by contact, but also includes devices formed to emit the impactors for excavating as described herein. In one example the device comprises a cutting member disposed on the end of a tubular, where the tubular includes impactors in a pressurized fluid. The cutting member provides a base on which an ejector element, such as a nozzle, is mounted and also communicates the ejectors and fluid to the ejector. Examples of such cutting members include cutting heads, lead mills, and any bit or mill modified to eject impactors for eroding an object. Accordingly the bit2017of the present disclosure can excavate without physically contacting what is being excavated, i.e. formation or object. Additionally, the present disclosure includes eroding or milling in a wellbore using any system that directs impactors at an object (or formation) with sufficient velocity to fracture and thereby erode the object (or formation), whether or not the system includes a drilling capability. The term velocity as used herein includes its technical definition having components of speed and direction. Thus sufficient velocity means the speed and direction of the impactor upon collision with the object's surface forms a fracture in the object.

An opening or window through casing can be created in numerous ways with particles.FIG. 21provides an example of a particle impact drilling (PID) apparatus used for milling a casing window. In this embodiment, the PID apparatus2001is disposed in a wellbore2003lined with casing2007. The PID apparatus includes a drilling string2015having a bit2017or cutting head on the end of the string2015. A whipstock assembly2009is optionally anchored in the casing2007for angling the PID apparatus2001into cutting contact with the casing2007. The bit2017may include specifically oriented nozzles to create a casing window2011or opening. As will be understood by those skilled in the art, the cutting head2017can be rotated on the drill string2015such that the placement and direction of the nozzle(s) can quickly remove all or parts of the casing target area. The nozzle(s) can be oriented in such a way that just an annular ring is cut in the casing and the remaining casing can drop into the borehole after being cut loose.

FIG. 22illustrates an example of a bit2017arotatable about the bit rotational axis ARby forces developed from the angle of the nozzle2022. The nozzle2022may be oriented to direct a discharge stream lateral to the bit2017aor drill string, that is roughly perpendicular to the drill string and/or bit2017aaxes. The nozzle2022may or may not be aligned with the stream it produces. The nozzle2022may also be oriented oblique to the axes, i.e. some other than 90° to the string or bit2017aaxes. Optionally, a nozzle may be oriented on the drill string2015that does not have to be rotated from the surface to cut a window in the casing. A geometry pattern can be followed with at least a single nozzle to cut the periphery of a window in the casing without rotating a drill string from the surface. Nozzles can be aligned such that overlapping areas of impact can remove the window in the casing without drill string rotation (step108).

Other downhole milling operations as well may be performed with a PID apparatus according to embodiments of the present invention. The PID apparatus is capable of removing materials from soft and elastic to ultra hard and tough, many parts, tools, and other debris not intended to be left in the hole can be drilled. Unlike conventional cutting structures, the PID apparatus may be used to cut ultra hard materials such as tungsten carbide and hardened steels, and ceramics as well as elastomeric materials. Examples of devices downhole that may be milled by a PID system include those lost in the hole (i.e. fish in the hole). The present disclosure also includes an alternative method of removing any object from a wellbore by milling the item, such objects or items include a downhole tool, a drill bit, a tubular member, and anything lodged in the wellbore. The system and method eroding (or milling) described herein can erode objects that cannot be drilled. These include objects that rotate within the wellbore, thus attempts to drill through the object would instead merely rotate it. Similarly, drilling elastomers can also be problematic since they may deform under an applied drilling load thereby deflecting the drill from the elastomer. Directing impactors at an object produces, among other things, fatigue loading in the surface that is being eroded. Either a rotatable object or an elastomer can be fatigued with applied impactors to thereby erode (or mill) either the rotatable object or elastomer.

An example of another milling embodiment of an apparatus or system is provided inFIG. 23where a PID apparatus2049is configured to mill a bit2043attached to casing2045. In this example, the bit2043and casing2045is used to form a wellbore2041. As shown, the PID system2049includes a drill string2051having a bit2053on its terminal end. Impact particles directed from the system2049erode the casing bit2043from the end of the casing after it has been drilled to depth. All of the components of conventional drill bits, including hardened steel, tungsten carbide, diamond, elastomers, and other materials can be removed at a fast rate by impacting the bits with particles at high velocity.

Under Reaming

In many drilling applications it is advantageous to drill a larger diameter hole beneath an existing diameter borehole; a concept generally referred to as under reaming (see, e.g.,FIG. 24). It is necessary that drilling tools, bits, and the like must have an overall diameter less than the existing borehole through which they must pass to continue drilling deeper. Examples requiring under reaming include forming a larger hole to provide a larger area for cementing casing, placing expandable casing below existing casing, over cutting the diameter of the hole to prevent mobile formations from swelling and trapping the drill pipe and other tools downhole. As understood by those skilled in the art, salt and some anhydrites are formations which have almost instantaneous strain rates followed by creep both of which can trap the drill string or significantly reduce drilling performance from parasitic losses from the formation contact.

Drilling tools used to “open” the hole larger generally are either eccentric, lobed, or have expanding parts as part of the drill bit or separate pieces that may be added to the drill string above the bit. In any case the bits and tools must be able to pass through the existing borehole prior to being activated or drill the larger hole. Eccentric bits and tools have not been totally reliable in increasing the hole size to the desired diameter for the interval to be opened up or leaving sections of the interval at a smaller than desired diameters both of which are not acceptable. Tools that are added to the drill string either directly above the bit or in the drill string somewhere above the bit can add bending stress to the tool joint when rotating and cutting. This can cause cyclic failure of the tool joint which can lead to washouts or tools being left in the hole. The performance of these tools can be diminished as well. The cutting of the extra hole is not obtained for free. Additional torque is required or the available torque must be shared both of which can reduce the performance by reducing the rate of penetration or add operational costs in developing more horsepower to drive the tools. Most conventional drilling bits and tools are dependent on high hydraulic horsepower to clean and cool the cutting structure(s). Usually the hydraulic horsepower must be also split downhole to feed both cutting tools and can significantly reduce the drilling performance.

As discussed above, PID technology has demonstrated it can excavate through hard formations at 3-5 times the rate of conventional drill bit systems. Laboratory tests indicate a PID system can penetrate metals and metal composites at higher rates as well. As described above and in the referenced patents and patent applications, the PID system includes an injections means that deposits a small volume percent of the total downhole fluid flow with particles (impactors). The impactors can be transported to the bit or cutting head and accelerated through nozzles to velocities sufficient to deliver the energy required to fail and erode the surface by impactor contact. The conventional fluid flow rate for oil and gas excavating operations imparts several million impacts per minute onto the excavation surface. After impact the impactors migrate to the surface for recovery and reinjection into the pressurized circulating fluid stream downhole.

PID technology can be used for under reaming by forming a device having a drill string2069configured to convey therefrom a plurality of impactors in a fluid under pressure. Because the mechanical energy required for under reaming is low, a PID bit may operate at 7000 to 15,000 pounds weight on bit, and because of no cutting structure on the bit, torque is low. The applied torque is only what is required to break the rock ring(s) in tension as the ring(s) is loaded against the angled rock breakers on the bit body. A bit2071may be included affixed to the drill string2069configured to receive the impactors in the fluid under pressure. The impactors may exit the bit2071through a nozzle2073configured to eject the impactors and fluid under pressure from the bit2071at high velocity so that the nozzle discharge is angled with respect to the wellbore axis for selectively increasing wellbore diameter.

FIG. 24illustrates an example of a PID system2067used for under reaming operations. In this embodiment, the PID system2067includes a drill string2069with an attached bit2071disposed in a wellbore2061.FIG. 30illustrates a flow chart outlining an example of a method of using the PID system2067, the method includes deploying the system2067in a wellbore (step110). The wellbore2061has an upper portion2063and lower portion2065. The lower portion diameter exceeds the upper portion diameter as illustrated. The increased lower portion diameter is formed by selectively activating the under reaming options of the PID system2067at a desired depth within the borehole2061by ejecting impactors from the system that are directed at the wellbore wall (step112).

Nozzles2073are shown disposed on the bit2071and angled downward. When in fluid communication with a mixture of impactors and pressurized circulating fluid, the nozzles2073can produce a spray pattern2075directed generally downward from the bit2071, Nozzles2074are also provided on the system2067above the placement of the bit2071. As shown, the upper nozzles2074are oriented generally perpendicular to the axis of the system2067. Thus when in fluid communication with a mixture of impactors and pressurized circulating fluid the nozzles2074form a corresponding flow pattern2076lateral to the PID system2067. Thus, selectively activating one or both of the nozzles (2073,2074) can excavate within a wellbore thereby creating a borehole section having diameter greater than a section at a lower depth. Optionally the nozzles (2073,2074) can be positioned at various angles ranging from parallel to perpendicular to the PID system2067. For example, one or more nozzles may be directed off of the bit face and angled towards being perpendicular to the axis of the borehole. Nozzles may be optionally located on the drill string (step116). In this orientation the particles leaving the nozzle will impact the formation at near perpendicularity and cut the additional hole more efficiently.

As will be understood by those skilled in the art, additional nozzles can be located at any location on the bit body. The orientation can be directed uphole as well as downhole. The uphole orientation will again cut any formation that has moved inwardly after the bit has passed. It would allow an “up drill” feature to aid in drilling out of the hole if a formation has sloughed in behind the bit and would create restrictions when the bit is tripped out of the hole. Additional tools can be added to the drill string which contain nozzles and can under ream above the bit as well. The PID technology can easily under ream boreholes faster than conventional methods with little applied mechanical energy. The PID low weight on bit, the drill string buckling and deviation problems associated with conventional under reaming with high weights on bit are avoided. PID technology enables directing the tool as desired without additional stabilizing tools.

Removing Near Borehole Damage

Most Oil and Gas wells are drilled using drilling mud, which has a variety of base fluids including water, oil, foam, and brines. The different types of muds are used in applications where their attributes are specific to the well conditions. Although there are many mud types, they all perform some basic functions. The muds carry entrained weighting materials, clays, and chemicals going into the borehole and they get additional cuttings, from the drilling process, which are added to drilling fluid as it moves from the bottom of the borehole to the surface.

The clays and weighting materials added to the mud are usually very fine in size. Many of the cuttings generated from conventional bits also are very fine in size as they are ground and reground during the drilling process. The weighting material is added to the fluid to increase the pressure the drilling fluid exerts on the borehole walls to maintain a greater pressure than that of the formation. This higher pressure keeps the pressurized oil and gas from escaping to the borehole and is called overbalanced drilling.

The formations that produce oil and gas contain pores in their fabric, as well as, channels that connect the pores, giving the formation permeability (the ability to transport hydrocarbons through the formation) when the well is eventually produced. Because the wellbore pressure is higher than the formation pore pressure, drilling mud is forced into the connected pores. The fluid phase of the drilling fluid is transported into the borehole walls and leaves the fine particles of clay, weighting material, and cuttings on and into the near surface of the producing borehole formation. This residual agglomeration of particles is called filter cake or mud cake and is particularly an issue, as permeability is reduced, when producing from an open hole or perforations.

Because the permeability of the filter cake can be very low, it aids in “sealing off the formation from additional fluid loss (spurt loss) to the formation. The sealing of the formation to additional fluid is advantageous, but the sealing process usually involves some of the very fine particles entering the formation pore spaces and traveling through the pores and connecting channels until the channel opening becomes too small to accept the particles. The particles, still being forced by the pressure differential between the borehole and the formation pressure, jam up the throats of the channels. As the largest particles are wedged into the pore throats, the openings between the pore opening and the particle are reduced in diameter, which intern can then be blocked by smaller particles. Basically the permeability of the formation is drastically reduced and in some cases becomes negligible.

When the well is completed, the filter cake may be removed by a variety of methods, as understood by those skilled in the art, but, the internal reduction of permeability in the near borehole is not easily removed as it was jammed into the pore throats under dynamic fluid pressure. When the hydrocarbons are introduced into the borehole by lowering the borehole pressure, some of the internal pore throat bridges are removed while many are not. The net effect can be a significant reduction of formation permeability due to a relatively thin zone at the borehole wall. This zone acts as a filter that limits the amount of production passing through it. Because the damaged zone is relatively thin, and near the surface, some wells are subjected to an acid treatment in an attempt to dissolve these bridges and increase production.

As discussed above, PID technology has demonstrated it can excavate through hard formations at a rate 3-5 times that of a conventional drill bit systems. Laboratory tests indicate a PID system can penetrate metals and metal composites at higher rates as well. As described above and in the referenced patents and patent applications, the PID system includes an injections means that deposits a small volume percent of the total downhole fluid flow with particles (impactors). The impactors are transported to the bit or cutting head where the impactors are accelerated through nozzles to velocities sufficient to deliver the energy required to fail and erode an impacted surface. The conventional fluid flow rate for oil and gas excavating operations imparts several million impacts per minute onto the excavation surface. After impact the impactors migrate to the surface for recovery and reinjection into the pressurized circulating fluid stream downhole.

A particle impact drilling system, such as described herein, may be employed for removing filter cake. The system can include a cutting head2087attached to tubing2087configured to convey a mixture of impactors and pressurized circulating fluid to the cutting head2087. A nozzle2089may be included that is in fluid communication with the tubing2087pin one embodiment the nozzle2089is on the cutting head2087. The nozzle2089being in fluid communication with the tubing and configured to eject the impactors in the fluid under high pressure. A method of using the particle impact system is demonstrated in the flow chart ofFIG. 31. The method includes providing a PID system (step120) inserting the cutting head2087of the particle impact drilling system2083into a borehole2081and ejecting impactors from the nozzle2089against the wall2082of the wellbore2081(step122) thereby eroding filter cake and fracturing a portion of the surrounding formation with the ejected impactors. Fracturing the surrounding formation removes material and enlarges the borehole, which treats near bore producing formation damage by its removal (step124). This method also increases the wellbore wall permeability (step126).

PID technology can be utilized to remove wellbore mudcake by attaching a nozzle carrier to a drill string or tubular, then advancing and rotating the device in a borehole such that the damaged zone is removed at high rates of speed thereby leaving a production enhanced borehole surface.FIG. 25illustrates a method of using a PID system2083within a wellbore2081for removing mudcake/filter cake2093from the wellbore wall2082. In this embodiment, the system2083includes a cutting head2087disposed on the terminal end of a tubing string2085. The cutting head2087includes nozzles2089formed to direct a spray pattern2091at the wellbore wall2082for removing the filter cake2093formed on the outer surface of the wall2082. The system2083may optionally include a single nozzle, nozzle(s) may be disposed on the tubing string2085, or the tubing string2085may include the sole nozzle carrier. Nozzle rotation within the borehole2081may occur by rotating the system2083from the surface, or by disposing a nozzle on the system2083at an angle to the system axis thereby using fluid discharge dynamics for system rotational energy (step130). Nozzles may be configured to produce rotation of the cutting head2087about the cutting head rotational axis AR. In one example, the nozzle extends outwardly from the cutting head outer surface at a radial angle from the cutting head rotational axis AR, the angle may be preselected such as for example to maximize rotational force imparted onto the cutting head by the fluid exiting the nozzle. The fluid spray2091may be substantially as above described and thus include impactors. In one example of use of the system described herein, the radial thickness of the material removed from the wellbore inner circumference can exceed 0.5 inches. Since filtercake thickness typically ranges around 0.1 inches, the zone of erosion extends past the inner filtercake layer and into the near borehole, which provides for repair of near borehole damage. Repair of near borehole damage requires the impactors collide with the borehole wall with sufficient force to produce surface fractures in the formation surrounding the borehole. The present system therefore can remove filtercake and repair near borehole damage at the same time while improving permeability at the wellbore wall. The force of impact by the impactors on the wellbore wall depends on many factors, such as nozzle exit speed, annulus fluid properties, and the angle at which the impactor strikes the wall. In one embodiment, the nozzles may be gimbaled or angled with respect to the cutting head axis and the wellbore wall to thereby produce the desired impact force. The wellbore may be lined with casing after treatment (step128).

Assisted Annular Flow

As discussed above, particle impact drilling systems, like typical drilling systems, recirculate drilling fluid in the annulus formed between the drill string and the wellbore inner diameter. Due to variations in annulus dimensions, drill pipe connections, rig and surface repairs or calibrations and running pills and slug flows, the recirculating flow may experience low flow zones. The low flow zones can allow high density particles in the fluid begin to move downhole due to gravity. Depending on the time the flow is off and the hole geometry, some areas in the annulus can accumulate high percentages of particles as the falling particles tend to mass in sections of the annulus. While flowing, sections of the annulus tend to accumulate a larger volume of particles. This usually occurs in areas where the annular velocity is reduced such as washed out areas of the borehole and an increase in casing inner diameter.

In these areas of accumulation of particles, it can be desirous to increase the local velocity by adding flow through the drill string (added subs most likely) at higher velocities than the annular velocity. The additional areas of higher velocity, tends to break up the accumulation of particles and get them flowing back to the surface. The break up of these areas of accumulation is valuable because the mass of particles tends to create areas where pressure energy is absorbed as the fluid travels through the circuitous paths in the particle mass. The preservation of pressure energy is one of the keys to successful drilling. These locations for increasing the local annular velocity can be placed anywhere in the drill string or surface equipment including the BOP stack as understood by those skilled in the art. It will be understood that assisted flow means can be employed in conjunction with the bit or separately as well conditions dictate.

As discussed above, PID technology has demonstrated it can excavate through hard formations 3-5 times the rate of conventional drill bit systems. Laboratory tests indicate a PID system can penetrate metals and metal composites at higher rates as well. As described above and in the referenced patents and patent applications, the PID system includes an injections means that deposits a small volume percent of the total downhole fluid flow with particles (impactors). The impactors are transported to the bit or cutting head where the impactors are accelerated through nozzles to velocities sufficient to deliver the energy required to fail and erode an impacted surface. The conventional fluid flow rate for oil and gas excavating operations imparts several million impacts per minute onto the excavation surface. After impact the impactors migrate to the surface for recovery and reinjection into the pressurized circulating fluid stream downhole.

PID technology can be used for enhancing the flow of a drilling fluid in the annulus between a wellbore and a drill string, one embodiment of this method is illustrated in the flow chart ofFIG. 32. A wellbore2103is excavated with a drilling system2101(step140). The drilling system may include a bit2115disposed on the end of a drill string2113. Pressurized drilling fluid is introduced into the drill string2113for delivery to the drill bit2115. The pressurized drilling fluid exits the bit2115and flows up the wellbore2103. A nozzle2109is included with the drilling system2101and is in fluid communication with the pressurized drilling fluid (step142). Pressurized fluid is introduced into the drill string2113that flows to and out of the bit2115and back up the wellbore2103(step144). The method includes selectively discharging pressurized drilling fluid from the nozzle2109into the annulus2106at localized low pressure regions to perturb the regions and promote annular flow of drilling fluid along the wellbore2103(step146). The nozzle2109may be on the drill string2113.

FIG. 26illustrates a specific embodiment of a drilling system2101having nozzles2109positioned for perturbing low flow zones in the drill string/wellbore annulus. The drilling system2101may include a standard wellbore drilling system as well as one employing particle impact drilling technology. The system2101includes a string2113having a drill bit2115affixed to its lower end. The embodiment of the system2101is used to form a wellbore2103through a formation2104. A discontinuity2107on the wall2105of the wellbore2103allows fluid2108and debris (including impact particles) to accumulate and form a low flow region in the annulus2106. Nozzle(s)2109are provided on the string2113and configured to direct a fluid spray2111away from the string2113towards the wellbore wall2105. The fluid spray2111has sufficient momentum so that its impact on the low flow zone sufficiently perturbs the fluid2108and enables it to reemerge into the fluid flow Afflowing through the annulus2106towards the surface.

Coring Using a Particle Impact System

The most common method of obtaining reservoir and other downhole formations for analysis is coring. Coring usually consists of a core bit and a core barrel. The core bit can be of many different types depending on the target formation to be cored. The core bit, in general, has the outer portion of the bit having a cutting structure and the center of the bit being open. This configuration is reminiscent of a doughnut. The outer annular area has cutters attached to it and cuts a kerf in the formation while leaving the center portion of the rock intact. This center portion of rock is the core, or “undisturbed” part of the infinite reservoir or formation that has been left uncut and standing proud of the bottom hole. Depending of the strength of the rock being cut, different types and styles of core bits are used. In softer and medium strength rocks, core bits containing a cutting structure of polycrystalline diamond has advantages because of its faster rate of penetration and the ability of obtaining uninvaded core. As the rock becomes harder, core bits having a cutting structure of natural diamonds are often used. These bits cut slow but are able to cut harder rock while having a long cutting life. Hard and ultra hard rocks are usually cored with bits containing synthetic diamond crystals imbedded in a metallic composite matrix, more commonly known as an impregnated diamond core bit. The depth of cut is very small, so the rate at which the core is cut also very slow. One method that is used to increase the rate of penetration is to increase the rotary speed by tying the core bit and barrel to a hydraulic downhole motor or turbine. Although this can increase the performance, the rate at which these harder rocks are cored is still quite slow.

The conventional core bits as described above use mechanical energy to cut the formation surrounding the core. This is done by rotating the drill string from the surface and applying a force to the bit adding weight to it. The cutting and performance is dependant of the torque produced. Although torque is needed to cut the formation around the core, it can also be detrimental in obtaining an undamaged core or cutting the desired length of core (rock) to be brought to the surface for analysis. As the core is being produced by continually cutting the formation external to the core, the core becomes essentially a cylinder of rock that the core barrel its inner barrel is slipped over the core as the core bit advances into the target formation. These columns of cut core typically are in the neighborhood of 30 to 60 feet long but have recovered being almost 600 feet in length. The ability to obtain the desired length of core for a single run can be can be altered drastically by the torque developed at the core bit. With moderate to high levels of torque, the core entering the core barrel can easily be caught when torque fluctuations cause the bit or barrel to bind against the core and easily break the core. Rotary speed can also cause the core to break as the drilling fluid between the outer barrel and the inner barrel of the core barrel creates enough shear forces on the inner barrel to make it rotate and apply torque directly to the core.

Normally cores are not recovered intact but will be broken periodically. It is when the core does not break approximately perpendicular to the longitudinal axis of the core where many problems arise. If the break is at an angle to the axis of the core, and the core can slip along this fracture plane, it can become a radially loaded plug and prohibit the core from advancing into the barrel. If the core cannot advance into the barrel, the bit cannot continue to care at a reasonable rate and in many cases the penetration is stopped. The loads that are applied via the angled fracture are larger if there is an appreciable amount of core in the barrel as the weight of the core forces the core to slip along the fracture plane and develop very high lateral loads which jam the core in the barrel.

The value of a core is based on size of the core taken, the amount of damage the core has experienced, and accurate depth history. The cost of coring is an issue that is always analyzed in terms of cost benefit. The speed at which a core can be taken is a major part of the cost to benefit equation. Deep, hard, or lensed formations can take a significant amount of rig time, therefore cost, to obtain. Side wall coring has been used in some cases to defer the cost of full hole coring. A series of strong tubes attached to a downhole tool can be shot into the side of a borehole, where the formation is trapped in the tubes and recovered. Some small diameter core heads and drills have been used to cut small and short cores from the hole wall. The drawback to sidewall coring is the small diameter and volume of the core produced and the damage that is done while shooting into the formation. The types of rock fabric and mineralogy can be gleaned from these samples but critical reservoir information is most likely not obtainable from the small samples.

As discussed above, PID technology has demonstrated it can excavate through hard formations 3-5 times the rate of conventional drill bit systems. Laboratory tests indicate a PID system can penetrate metals and metal composites at higher rates as well. As described above and in the referenced patents and patent applications, the PID system includes an injections means that deposits a small volume percent of the total downhole fluid flow with particles (impactors). The impactors are transported to the bit or cutting head where the impactors are accelerated through nozzles to velocities sufficient to deliver the energy required to fail and erode an impacted surface. The conventional fluid flow rate for oil and gas excavating operations imparts several million impacts per minute onto the excavation surface. After impact the impactors migrate to the surface for recovery and reinjection into the pressurized circulating fluid stream downhole.

A device employing PID technology can be used for retrieving subterranean core samples. The device may include an elongated body2129and a core bit2131affixed to the lower end of the body2129. A cutting surface may be included with the bit2131having a nozzle2133formed on the core bit cutting surface. The nozzle2133as shown is configured for discharging impactors in a pressurized fluid at high velocity for cutting through formation2128to obtain core samples. The body2129may be configured to receive core samples therein.

An example of a coring system2125employing particle impact technology is illustrated inFIG. 27. The coring system2125includes a generally cylindrically shaped body2129configured to transfer rotational force to a particle impact cutting head2131. The body2129is also shaped to receive a core sample2127within its annular opening. The cutting head2131as shown includes nozzles2133that receive and discharge a mixture of impactors and pressurized circulating fluid. The mixture discharges from the nozzles2133to create a stream2135having impactors, the stream2135is directed at the formation2128from which a core sample2127is to be retrieved. A method of use is illustrated inFIG. 33, where the method includes providing the coring system2125(step150). The coring end (cutting head2131) is directed at the subterranean formation2128(step152) and impactors and fluid are discharged from the nozzles2133that impact and fracture the formation2128(step154). This creates a kerf in the formation2128that defines the sample core outer periphery (step156). The coring end is further urged into the formation which further forms the core sample2127that is received in the body2129(step158). The core end can be fractured and retrieved from the wellbore (160). This procedure can be done for bottom hole or side wall coring.

Cutting head2131embodiments exist having multiple nozzles2133arranged on the body2129opening that form a stream2135that circumscribes the core sample2127. Optionally, the cutting head2131rotates to orbit the nozzles2133around the body2129axis to thereby form the kerf. Rotating the cutting2131can require fewer nozzles2133, possibly as few as a single nozzle2133. Implementing particle impact technology for core sampling can increase sample core diameter, which is due in part because the particle impingement produces thinner kerfs. Larger cores are less likely to be damaged by applied torque but are subjected to minimal torque since the cutting structure is not dependent of torque to excavate rock formations. In addition the performance of PID can be produced with very low rotary speed, which also reduces applied torque to the core.

The high rates of penetration exhibited by PID positively affect the reduction of damage to a core by invasion or fluid displacement as these are dependent on the time a core is exposed to the drilling fluid and the degree of damage to the filter cake that dynamically and statically form on the exterior or the core. Larger diameters will also provide more undamaged core as the depth of the invasion damage takes place on the exterior of the core and is uniform in depth if left undisturbed leaving a larger diameter of undamaged core. By having the ability to cut larger diameter cores and thinner kerfs makes PID coring a vastly improved technique for coring, including sidewall coring as understood by those skilled in the art. Larger diameter cores can be taken potentially without secondary power sources by allowing the PID nozzle heads to rotate using the forces created by angling the jets enough to establish rotation. PID technology performance is almost independent of rotary speed so applied torque is minimal.

It is recognized that although conventional core barrels might function with the PID technology, fit for purpose core barrels containing dedicated flow channels that feed the nozzle(s) with high pressure fluid laden with particles might be needed to extract the full performance of the PID coring system.

After a wellbore has been drilled and cased with steel pipe cemented in the hole, the borehole is without communication to the producing formations that it was most likely drilled to produce. The most common methods of establishing communication from the producing formations and the borehole are through “perforating”. Perforating can use means to open holes through the casing and attaching cement into the producing formations. The continuous hole through the casing and into the producing formation allows crude petroleum and natural gas to migrate to the lower pressure borehole where it flows or is pumped to the surface for collection.

Early methods of perforating included the use of lowering “guns”, strings of radial oriented bullets in small diameter steel housing, to the depth of the production interval of interest and firing the gun. Bullets, after being fired, travel through the casing and into the formation creating a channel behind them. This channel is commonly referred to as a carrot because of the shape of the channel which tapers inward from its entry into the formation to the diameter of the bullet. The bullet expends enough energy traveling through the casing or multiple casings and cement into the formation to create a relatively short wound channel or carrot. The rock at depth is stressed due to the overburden and horizontal stresses which increase with depth at about one pound per square inch per foot of depth. Not only are the producing formations by themselves strong, but at depth have significant additional strengthening from the stress of being buried.

Wild claims of the lengths of these carrots were published and advertised until surface tests with simulated stress conditions were performed. These tests showed carrots only a fraction of the lengths as previously thought. The carrots have a surface area based on the geometry and length. The much reduced surface area from the short carrots limited production as well as producing mostly from “near wellbore” portions of the production formation unless the carrot intersected a fracture that extended further into the formation. In addition to the carrots being much shorter than expected the bullets created very fine formation fragments as it was shot into the rock. These fragments were usually jammed into the walls of the carrot as it was being formed reducing its ability to produce. The carrots were flushed in many cases with acid in an attempt to remove the fragments nesting in the pore spaces of the rock and increase the formation permeability and therefore the production.

Although bullets may still be used to perforate the casing, newer technology was developed that overcame many of the shortcomings of bullet perforating. The development by the military to pierce armor found on tanks and the like, with a shaped charge, proved to be instrumental in the introduction of perforating using shaped charges. This is the most common and preferred method of perforating today

Perforating guns are loaded with many shaped charges aimed radially. The gun is tripped into the hole until the appropriated depth is reached. The gun(s) are set off electronically. The explosion of the charge is designed to strike the casing with a high velocity and high temperature wave front which removes the casing, cement and formation. The results of the shape charge produced carrot are significantly longer that the bullet formed carrots. Depending on the increasing strength of the stressed formation, the performance of the shape charge perforation can be severely reduced.

As discussed above, PID technology has demonstrated it can excavate through hard formations 3-5 times faster than conventional drill bit systems. Laboratory tests indicate a PID system can penetrate metals and metal composites at higher rates as well. As described above and in the referenced patents and patent applications, the PID system includes an injection means that deposits a small volume percent of the total downhole fluid flow with particles (impactors). The impactors are transported to the bit or cutting head where the impactors are accelerated through nozzles to velocities sufficient to deliver the energy required to fail and erode an impacted surface. The conventional fluid flow rate for oil and gas excavating operations imparts several million impacts per minute onto the excavation surface. After impact the impactors migrate to the surface for recovery and reinjection into the pressurized circulating fluid stream downhole.

PID technology can be used for perforating a wellbore with a perforating system2151. It should be noted that by perforating with the PID system the type of damage to the carrot surfaces by conventional means is virtually eliminated. As illustrated inFIG. 28, one embodiment of a perforating system2151includes a base unit2155, tubing2153connected to the base unit2155, a member2158on the base unit2155having a nozzle2164formed therein, a member2163on the base unit2155selectively extendable from the base unit2155, and a nozzle2169on the free end of the member2163. Embodiments of the perforating system2151also include a base unit2155with only nozzles affixed thereon, only selectively extendable members, or combinations thereof. The tubing2153selectively communicates pressurized fluid having impactors to the base unit2155for delivery to one or more of the nozzles (2164,2169,2170). In an example of use of this method, as shown in the flow chart ofFIG. 34, a system2151as described above is provided for use (step180). The base unit2155is disposed into a wellbore2157(step182) and pressurized fluid having impactors is supplied to the tubing2153(step184). The nozzle2164is directed at the wellbore wall (step190). The tubing2153is put into fluid communication with the member2158and thus the nozzle2164, where fluid containing impactors exits the nozzle2164forming a spray pattern2160directed at the casing2161. The spray pattern2160containing the impactors erodes the casing2161and surrounding formation2159to create a perforation2162. Perforating members2163and2163aare selectively extendable (step186) from a stowed position where their respective nozzles (2169,2170) are adjacent the base unit2155to an extended or deployed position away from the base unit2155as shown inFIG. 28. The command to extend may be from the wellbore surface. Fluid can be communicated to the members (2163,2163a) while in the stowed position, the deployed position, or while extending. Communicating fluid to the perforating member2163in turn communicates the fluid with the nozzle2169(step188) thereby providing fluid containing impactors to the nozzle discharge. The nozzles2169with exiting impactors are directed at the casing2161(step190) and erode through the casing2161and formation2159to form perforations2173through the wellbore2157.

In one specific example of perforating using perforating impact technology, a nozzle having exiting impactors is used to excavate formation adjacent a wellbore. The nozzle may be placed at the tip of a limber supply tube and positioned such that as the impactors are accelerated through the nozzle to impact the wellbore casing and form a path into the surrounding formation. An embodiment of a PID perforating system2151is shown schematically inFIG. 28. The system2151includes a body2155suspended in a wellbore2157by tubing2153. The tubing2153thus can support the body2155and provide a conduit for pressurized fluid and associated impactors. After forming a perforation in one location, the system may be relocated in the wellbore2157at another depth for one or more perforations (step192).

A perforating member2163is shown laterally extending from the body2155and forming a perforation2173through casing2161that lines the wellbore2157and into the surrounding formation2159. The member2163includes an extendable shaft2165having excavating means on its end for forming the perforation2173. The excavation means includes a shaft end2167having a nozzle2169for directing an excavating impact fluid spray (or stream)2171at the formation2159, where the fluid spray2171comprises a mixture of impactors in a pressurized circulating fluid. Because the shaft2165is extendable, the dimensions of the resulting perforation2173are only limited by the dimensions of the shaft2165. The system2151may include multiple excavating members. An optional embodiment of an extendable member2163aemploys an end2167ahaving dual nozzles2170for creating multiple spray flows2171afor excavating a perforation2173a.

The member2163can be advanced into the formation via mechanical means or hydraulics. A nozzle and supply tube can have force applied to it much like blowing into a closed drinking straw and advance due to those forces. Multiple nozzles and supply tubes can be utilized at the same in order to form many perforations at the same time.

It is also possible to form perforations from a fixed platform dropped into the cased borehole. Once the platform (gun) is in place fluid and impactors are flowed through each nozzle, creating an opening into the casing, cement and formation. The length and diameter of the perforation is dependant on the decay rate of the impactors and the strength of the rock. Although the time it takes is not as fast as a shaped charge, PID perforating can be done at high rates of penetration while leaving a much larger (higher surface area) carrot to improve production in both the short and long term. Those advantages far outweigh the difference in time to create a drastically improved perforation as time is not the driver to better perforating but the quality of the formed perforation.

In the drawings and detailed description, there have been disclosed typical embodiments of the invention, and although specific terms are employed, the terms are used in a descriptive sense only and not for purposes of limitation. The invention has been described in considerable detail with specific reference to these illustrated embodiments. It will be apparent, however, that various modifications and changes can be made within the spirit and scope of the invention as described in the foregoing specification and as defined in the attached claims.