Source: https://patents.google.com/patent/US7909116
Timestamp: 2018-03-20 07:34:59
Document Index: 432219853

Matched Legal Cases: ['Application No. 2', 'Application No. 2', 'Application No. 04759869', 'Application No. 5771403', 'Application No. 2004', 'Application No. 2005', 'Application No. 34', 'Application No. 98', 'Application No. 20055409', 'Application No. 20070997', 'Application No. 1484']

US7909116B2 - Impact excavation system and method with improved nozzle - Google Patents
Impact excavation system and method with improved nozzle
US7909116B2
US7909116B2 US11204862 US20486205A US7909116B2 US 7909116 B2 US7909116 B2 US 7909116B2 US 11204862 US11204862 US 11204862 US 20486205 A US20486205 A US 20486205A US 7909116 B2 US7909116 B2 US 7909116B2
US11204862
US20060011386A1 (en )
Gordon Allen Tibbitts
PDTI Holdings LLC
A system and method for excavating a subterranean formation, according to which a suspension of liquid and a plurality of impactors is introduced into at least one cavity formed in the body member. The suspension is discharged from a nozzle disposed in the cavity towards the formation so that the impactors remove at least a portion of the formation.
This application is a continuation-in-part of pending application Ser. No. 10/897,196, filed Jul. 22, 2004 which, in turn, is a continuation-in-part of pending application Ser. No. 10/825,338, filed Apr. 15, 2004, which, in turn, claims the benefit of 35 U.S.C. 111 (b) provisional application Ser. No. 60/463,903, filed Apr. 16, 2003, the disclosures of which are incorporated herein by reference.
This disclosure relates to a system and method for excavating a formation, such as to form a well bore for the purpose of oil and gas recovery, to construct a tunnel, or to form other excavations in which the formation is cut, milled, pulverized, scraped, sheared, indented, and/or fractured, (hereinafter referred to collectively as “cutting”). The cutting process is a very interdependent process that preferably integrates and considers many variables to ensure that a usable bore is constructed. As is commonly known in the art, many variables have an interactive and cumulative effect of increasing cutting costs. These variables may include formation hardness, abrasiveness, pore pressures, and formation elastic properties. In drilling wellbores, formation hardness and a corresponding degree of drilling difficulty may increase exponentially as a function of increasing depth. A high percentage of the costs to drill a well are derived from interdependent operations that are time sensitive, i.e., the longer it takes to penetrate the formation being drilled, the more it costs. One of the most important factors affecting the cost of drilling a wellbore is the rate at which the formation can be penetrated by the drill bit, which typically decreases with harder and tougher formation materials and formation depth.
One attempt to increase the effective rate of penetration (ROP) involved high-pressure circulation of a drilling fluid as a foundation for potentially increasing ROP. It is common knowledge that hydraulic power available at the rig site vastly outweighs the power available to be employed mechanically at the drill bit. For example, modem drilling rigs capable of drilling a deep well typically have in excess of 3000 hydraulic horsepower available and can have in excess of 6000 hydraulic horsepower available while less than one-tenth of that hydraulic horsepower may be available at the drill bit. Mechanically, there may be less than 100 horsepower available at the bit/rock interface with which to mechanically drill the formation.
Another effort to utilize the hydraulic horsepower available at the bit incorporated the use of ultra-high pressure jet assisted drilling. A group known as FlowDril Corporation was formed to develop an ultra-high-pressure liquid jet drilling system in an attempt to increase the rate of penetration. The work was based upon U.S. Pat. No. 4,624,327 and is documented in the published article titled “Laboratory and Field Testing of an Ultra-High Pressure, Jet-Assisted Drilling System” authored by J. J. Kolle, Quest Integrated Inc., and R. Otta and D. L. Stang, FlowDril Corporation; published by SPE/IADC Drilling Conference publications paper number 22000. The cited publication disclosed that the complications of pumping and delivering ultrahigh-pressure fluid from surface pumping equipment to the drill bit proved both operationally and economically unfeasible.
Another effort at increasing rates of penetration by taking advantage of hydraulic horsepower available at the bit is disclosed in U.S. Pat. No. 5,862,871. This development employed the use of a specialized nozzle to excite normally pressured drilling mud at the drill bit. The purpose of this nozzle system was to develop local pressure fluctuations and a high speed, dual jet form of hydraulic jet streams to more effectively scavenge and clean both the drill bit and the formation being drilled. It is believed that these hydraulic jets were able to penetrate the fracture plane generated by the mechanical action of the drill bit in a much more effective manner than conventional jets were able to do. ROP increases from 50% to 400% were field demonstrated and documented in the field reports titled “DualJet Nozzle Field Test Report-Security DBS/Swift Energy Company,” and “DualJet Nozzle Equipped M-1 LRG Drill Bit Run”. The ability of the dual jet (“DualJet”) nozzle system to enhance the effectiveness of the drill bit action to increase the ROP required that the drill bits first initiate formation indentations, fractures, or both. These features could then be exploited by the hydraulic action of the DualJet nozzle system.
There are many variables to consider to ensure a usable well bore is constructed when using cutting systems and processes for the drilling of well bores or the cutting of formations for the construction of tunnels and other subterranean earthen excavations. Many variables, such as formation hardness, abrasiveness, pore pressures, and formation elastic properties affect the effectiveness of a particular drill bit in drilling a well bore. Additionally, in drilling well bores, formation hardness and a corresponding degree of drilling difficulty may increase exponentially as a function of increasing depth. The rate at which a drill bit may penetrate the formation typically decreases with harder and tougher formation materials and formation depth.
When the formation is relatively soft, as with shale, material removed by the drill bit will have a tendency to reconstitute onto the teeth of the drill bit. Build-up of the reconstituted formation on the drill bit is typically referred to as “bit balling” and reduces the depth that the teeth of the drill bit will penetrate the bottom surface of the well bore, thereby reducing the efficiency of the drill bit. Particles of a shale formation also tend to reconstitute back onto the bottom surface of the bore hole. The reconstitution of a formation back onto the bottom surface of the bore hole is typically referred to as “bottom balling”. Bottom balling prevents the teeth of a drill bit from engaging virgin formation and spreads the impact of a tooth over a wider area, thereby also reducing the efficiency of a drill bit. Additionally, higher density drilling muds that are required to maintain well bore stability or well bore pressure control exacerbate bit balling and the bottom balling problems.
When the drill bit engages a formation of a harder rock, the teeth of the drill bit press against the formation and densify a small area under the teeth to cause a crack in the formation. When the porosity of the formation is collapsed, or densified, in a hard rock formation below a tooth, conventional drill bit nozzles ejecting drilling fluid are used to remove the crushed material from below the drill bit. As a result, a cushion, or densification pad, of densified material is left on the bottom surface by the prior art drill bits. If the densification pad is left on the bottom surface, force by a tooth of the drill bit will be distributed over a larger area and reduce the effectiveness of a drill bit.
There are generally two main categories of modern drill bits that have evolved over time. These are the commonly known fixed cutter drill bit and the roller cone drill bit. Additional categories of drilling include percussion drilling and mud hammers. However, these methods are not as widely used as the fixed cutter and roller cone drill bits. Within these two primary categories (fixed cutter and roller cone), there are a wide variety of variations, with each variation designed to drill a formation having a general range of formation properties.
The fixed cutter drill bit and the roller cone type drill bit generally constitute the bulk of the drill bits employed to drill oil and gas wells around the world. When a typical roller cone rock bit tooth presses upon a very hard, dense, deep formation, the tooth point may only penetrate into the rock a very small distance, while also at least partially, plastically “working” the rock surface. Under conventional drilling techniques, such working the rock surface may result in the densification as noted above in hard rock formations.
With roller cone type drilling bits, a relationship exists between the number of teeth that impact upon the formation and the drilling RPM of the drill bit. A description of this relationship and an approach to improved drilling technology is set forth and described in U.S. Pat. No. 6,386,300 issued May 14, 2002. The '300 patent discloses the use of solid material impactors introduced into drilling fluid and pumped though a drill string and drill bit to contact the rock formation ahead of the drill bit. The kinetic energy of the impactors leaving the drill bit is given by the following equation: Ek=½Mass(Velocity)2. The mass and/or velocity of the impactors may be chosen to satisfy the mass-velocity relationship in order to structurally alter the rock formation.
FIG. 5 is a side elevational view of a drilling system utilizing a first embodiment of a drill bit;
FIG. 6 is a top plan view of the bottom surface of a well bore formed by the drill bit of FIG. 5;
FIG. 7 is an end elevational view of the drill bit of FIG. 5;
FIG. 8 is an enlarged end elevational view of the drill bit of FIG. 5;
FIG. 9 is a perspective view of the drill bit of FIG. 5;
FIG. 10 is a perspective view of the drill bit of FIG. 5 illustrating a breaker and junk slot of a drill bit;
FIG. 11 is a side elevational view of the drill bit of FIG. 5 illustrating a flow of solid material impactors;
FIG. 12 is a top elevational view of the drill bit of FIG. 5 illustrating side and center cavities;
FIG. 13 is a canted top elevational view of the drill bit of FIG. 5;
FIG. 14 is a cutaway view of the drill bit of FIG. 5 engaged in a well bore;
FIG. 15 is a schematic diagram of the orientation of the nozzles of a second embodiment of a drill bit;
FIG. 16 is a side cross-sectional view of the rock formation created by the drill bit of FIG. 5 represented by the schematic of the drill bit of FIG. 5 inserted therein;
FIG. 17 is a side cross-sectional view of the rock formation created by drill bit of FIG. 5 represented by the schematic of the drill bit of FIG. 5 inserted therein;
FIG. 18 is a perspective view of an alternate embodiment of a drill bit;
FIG. 19 is a perspective view of the drill bit of FIG. 18; and
FIG. 21A is an elevational view of a nozzle for use in the excavation system of FIG. 1.
FIG. 21B is a sectional view of the nozzle of FIG. 21A.
FIG. 22A is an elevational view of an alternate embodiment of a nozzle for use in the excavation system of FIG. 1.
FIG. 22B is a sectional view of the nozzle of FIG. 22A.
FIG. 23A is an elevational view of another alternate embodiment of a nozzle for use in the excavation system of FIG. 1.
FIG. 23B is a sectional view of the nozzle of FIG. 23A.
Each of the individual impactors 100 is structurally independent from the other impactors. For brevity, the plurality of solid material impactors 100 may be interchangeably referred to as simply the impactors 100. The plurality of solid material impactors 100 may be substantially rounded and have either a substantially non-uniform outer diameter or a substantially uniform outer diameter. The solid material impactors 100 may be substantially spherically shaped, non-hollow, formed of rigid metallic material, and having high compressive strength and crush resistance, such as steel shot, ceramics, depleted uranium, and multiple component materials. Although the solid material impactors 100 may be substantially a nonhollow sphere, alternative embodiments may provide for other types of solid material impactors, which may include impactors 100 with a hollow interior. 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 wellbore 70.
Introducing the impactors 100 into the circulation fluid may be accomplished by any of several known techniques. For example, the impactors 100 may be provided in an impactor storage tank 94 near the rig 5 or in a storage bin 82. A screw elevator 14 may then transfer a portion of the impactors at a selected rate from the storage tank 94, into a slurrification tank 98. A pump 10, such as a progressive cavity pump may transfer a selected portion of the circulation fluid from a mud tank 6, into the slurrification tank 98 to be mixed with the impactors 100 in the tank 98 to form an impactor concentrated slurry. An impactor introducer 96 may be included to pump or introduce a plurality of solid material impactors 100 into the circulation fluid before circulating a plurality of impactors 100 and the circulation fluid to the nozzle 64. The impactor introducer 96 may be a progressive cavity pump capable of pumping the impactor concentrated slurry at a selected rate and pressure through a slurry line 88, through a slurry hose 38, through an impactor slurry injector head 34, and through an injector port 30 located on the gooseneck 36, which may be located atop the swivel 28. The swivel 36, including the through bore for conducting circulation fluid therein, may be substantially supported on the feed, or upper, end of the pipe string 55 for conducting circulation fluid from the gooseneck 36 into the latter end 55 a. The upper end 55A of the pipe string 55 may also include the kelly 50 to connect the pipe 56 with the swivel quill 26 and/or the swivel 28. The circulation fluid may also be provided with rheological properties sufficient to adequately transport and/or suspend the plurality of solid material impactors 100 within the circulation fluid.
In addition to the impactors 100 satisfying the mass-velocity relationship described above, a substantial portion by weight of the solid material impactors 100 have an average mean diameter of between approximately 0.050 to 0.500 of an inch.
FIG. 2 illustrates an impactor 100 that has been impaled into a formation 52, such as a lower surface 66 in a wellbore 70. For illustration purposes, the surface 66 is illustrated as substantially planar and transverse to the direction of impactor travel 100 a. The impactors 100 circulated through a nozzle 64 may engage the formation 52 with sufficient energy to effect one or more properties of the formation 52.
The mechanical cutters, utilized on many of the surfaces of the drill bit 110, 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.
Referring now to FIG. 7, an end elevational view of the drill bit 110 of FIG. 5 is illustrated. The drill bit 110 comprises two side nozzles 200A, 200B and a center nozzle 202. The side and center nozzles 200A, 200B, 202 discharge drilling fluid and solid material impactors (not shown) into the rock formation or other surface being excavated. The solid material impactors may comprise steel shot ranging in diameter from about 0.010 to about 0.500 of an inch. However, various diameters and materials such as ceramics, etc. may be utilized in combination with the drill bit 120. The solid material impactors contact the bottom surface 122 of the well bore 120 and are circulated through the annulus 124 to the surface. The solid material impactors may also make up any suitable percentage of the drilling fluid for drilling through a particular formation.
Still referring to FIG. 7 the center nozzle 202 is located in a center portion 203 of the drill bit 110. The center nozzle 202 may be angled to the longitudinal axis of the drill bit 110 to create an excavated interior cavity 244 and also cause the rebounding solid material impactors to flow into the major junk slot, or passage, 204A. The side nozzle 200A located on a side arm 214A of the drill bit 110 may also be oriented to allow the solid material impactors to contact the bottom surface 122 of the well bore 120 and then rebound into the major junk slot, or passage, 204A. The second side nozzle 200B is located on a second side arm 214B. The second side nozzle 200B may be oriented to allow the solid material impactors to contact the bottom surface 122 of the well bore 120 and then rebound into a minor junk slot, or passage, 204B. The orientation of the side nozzles 200A, 200B may be used to facilitate the drilling of the large exterior cavity 46. The side nozzles 200A, 200B may be oriented to cut different portions of the bottom surface 122. For example, the side nozzle 200B may be angled to cut the outer portion of the excavated exterior cavity 146 and the side nozzle 200A may be angled to cut the inner portion of the excavated exterior cavity 146. The major and minor junk slots, or passages, 204A, 204B allow the solid material impactors, cuttings, and drilling fluid 240 to flow up through the well bore annulus 124 back 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 surface 122 to the annulus 124.
Referring now to FIG. 9, a side elevational view of the drill bit 110 is illustrated. FIG. 9 shows the gauge cutters 230 included along the side arms 214A, 214B of the drill bit 110. The gauge cutters 230 are oriented so that a cutting face of the gauge cutter 230 contacts the inner wall 126 of the well bore 120. The gauge cutters 230 may contact the inner wall 126 of the well bore at any suitable backrake, for example a backrake of 15° to 45°. Typically, the outer edge of the cutting face scrapes along the inner wall 126 to refine the diameter of the well bore 120.
Each side arm 214A, 214B fits in the excavated exterior cavity 146 formed by the side nozzles 200A, 200B and the mechanical cutters 208 on the face 212 of each side arm 214A, 214B. The solid material impactors from one side nozzle 200A rebound from the rock formation and combine with the drilling fluid and cuttings flow to the major junk slot 204A and up to the annulus 124. The flow of the solid material impactors, shown by arrows 205, from the center nozzle 202 also rebound from the rock formation up through the major junk slot 204A.
Referring now to FIGS. 10 and 11, the minor junk slot 204B, breaker surface, and the second side nozzle 200B are shown in greater detail. The breaker surface is conically shaped, tapering to the center nozzle 202. The second side nozzle 200B is oriented at an angle to allow the outer portion of the excavated exterior cavity 146 to be contacted with solid material impactors. The solid material impactors then rebound up through the minor junk slot 204B, shown by arrows 205, along with any cuttings and drilling fluid 240 associated therewith.
Referring now to FIGS. 12 and 13, top elevational views of the drill bit 110 are shown. Each nozzle 200A, 200B, 202 receives drilling fluid 240 and solid material impactors from a common plenum feeding separate cavities 250, 251, and 252. Since the common plenum has a diameter, or cross section, greater than the diameter of each cavity 250, 251, and 252, the mixture, or suspension of drilling fluid and impactors is accelerated as it passes from the plenum to each cavity. The center cavity 250 feeds a suspension of drilling fluid 240 and solid material impactors to the center nozzle 202 for contact with the rock formation. The side cavities 251, 252 are formed in the interior of the side arms 214A, 214B of the drill bit 110, respectively. The side cavities 251, 252 provide drilling fluid 240 and solid material impactors to the side nozzles 200A, 200B for contact with the rock formation. By utilizing separate cavities 250, 251, 252 for each nozzle 202, 200A, 200B, the percentages of solid material impactors in the drilling fluid 240 and the hydraulic pressure delivered through the nozzles 200A, 200B, 202 can be specifically tailored for each nozzle 200A, 200B, 202. Solid material impactor distribution can also be adjusted by changing the nozzle diameters of the side and center nozzles 200A, 200B, and 202 by changing the diameters of the nozzles. However, in alternate embodiments, other arrangements of the cavities 250, 251, 252, or the utilization of a single cavity, are possible.
Referring now to FIG. 15, an example orientation of the nozzles 200A, 200B, 202 are illustrated. The center nozzle 202 is disposed left of the center line of the drill bit 110 and angled on the order of around 20° left of vertical. Alternatively, both of the side nozzles 200A, 200B may be disposed on the same side arm 214 of the drill bit 110 as shown in FIG. 15. In this embodiment, the first side nozzle 200A, oriented to cut the inner portion of the excavated exterior cavity 146, is angled on the order of around 10° left of vertical. The second side nozzle 200B 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 cavity 244 to be created by the center nozzle 202. The side nozzles 200A, 200B create a large enough excavated exterior cavity 146 in order to allow the side arms 214A, 214B to fit in the excavated exterior cavity 146 without incurring a substantial amount of resistance from uncut portions of the rock formation 270. By varying the orientation of the center nozzle 202, the excavated interior cavity 244 may be substantially larger or smaller than the excavated interior cavity 244 illustrated in FIG. 14. The side nozzles 200A, 200B may be varied in orientation in order to create a larger excavated exterior cavity 146, thereby decreasing the size of the rock ring 142 and increasing the amount of mechanical cutting required to drill through the bottom surface 122 of the well bore 120. Alternatively, the side nozzles 200A, 200B may be oriented to decrease the amount of the inner wall 126 contacted by the solid material impactors 272. By orienting the side nozzles 200A, 200B at, for example, a vertical orientation, only a center portion of the excavated exterior cavity 146 would be cut by the solid material impactors and the mechanical cutters would then be required to cut a large portion of the inner wall 126 of the well bore 120.
Referring now to FIGS. 16 and 17, side cross-sectional views of the bottom surface 122 of the well bore 120 drilled by the drill bit 110 are shown. With the center nozzle angled on the order of around 20° left of vertical and the side nozzles 200A, 200B angled on the order of around 10° left of vertical and around 14° right of vertical, respectively, the rock ring 142 is formed. By increasing the angle of the side nozzle 200A, 200B orientation, an alternate rock ring 142 shape and bottom surface 122 is cut as shown in FIG. 17. The excavated interior cavity 244 and rock ring 142 are much more shallow as compared with the rock ring 142 in FIG. 16. It is understood that various different bottom hole patterns can be generated by different nozzle configurations.
An alternate embodiment of the nozzle that can be disposed in each cavity 251, 252, and 253 is shown in FIGS. 21A and 21B, and is referred to in general by the reference numeral 300. In particular, the nozzle 300 is in the form of a tubular body member 302 having an inlet portion 302 a disposed at one end portion of the body member for receiving the suspension of fluid and impactors 100 (FIGS. 2-4), and a discharge portion 302 b disposed at the other end portion of the body member for discharging the suspension. A constant-diameter bore 302 c connects the inlet portion 302 a and the discharge portion 302 b. The inner diameter of the bore 302 c is less than the inner diameter of the inlet portion 302 a, and the inner diameter of the discharge portion 302 b tapers radially outwardly from the corresponding end of the bore 302 c to the end of the discharge portion 302 b. The bore 302 c has a length that is as least as great as its inner diameter, and, according to the example of FIGS. 21 a and 21 b, the ratio of its length to its inner diameter is approximately twenty to one.
A set of threads 304 is provided on the outer surface of the body member 302 between the end portions thereof and is adapted to engage corresponding internal threads on the internal surface of the body member defining the cavities 251, 252, and 253. If it is desired to angle the body member 302 relative to the axis of its corresponding cavity 251, 252, and 253, as discussed above, the set of threads 304 and/or the corresponding internal threads would be configured accordingly.
Another embodiment of the nozzle that can be disposed in each cavity 251, 252, and 253 is shown in FIGS. 22A and 22B, and is referred to in general by the reference numeral 310. In particular, the nozzle 310 is in the form of a tubular body member 312 having an inlet portion 312 a disposed at one end portion of the body member for receiving the suspension of fluid and impactors 100 (FIGS. 2-4), and a discharge portion 312 b disposed at the other end portion of the body member for discharging the suspension. A constant-diameter bore 312 c connects the inlet portion 312 a and the discharge portion 312 b. The inner diameter of the bore 312 c is less than the inner diameter of the inlet portion 312 a, and the inner diameter of the discharge portion 312 b tapers radially outwardly from the corresponding end of the bore 312 c to the end of the discharge portion 312 b. The bore 312 c has a length that is as least as great as its inner diameter, and, according to the example of FIGS. 22 a and 22 b, the ratio of its length to its inner diameter is approximately twenty to one.
A set of threads 314 is provided on the outer surface of the body member 312 between the end portions thereof and is adapted to engage corresponding internal threads on the surface of the body member defining the cavities 251, 252, and 253. If it is desired to angle the body member 312 relative to the axis of its corresponding cavity 251, 252, and 253, as discussed above, the set of threads 314 and/or the corresponding internal threads would be configured accordingly.
Another embodiment of the nozzle that can be disposed in each cavity 251, 252, and 253 is shown in FIGS. 23A and 23B, and is referred to in general by the reference numeral 320. In particular, the nozzle 320 is in the form of a tubular body member 302 having constant-diameter bore portion 322 a extending from one end of the body member to a discharge portion 322 b formed at the other end of the body member. An inlet 322 c is provided at the one end of the bore 322 a for receiving the suspension of fluid and impactors 100 (FIGS. 2-4). The inner diameter of the discharge portion 322 b tapers radially outwardly from the other end of the bore 322 a to the end of the discharge portion 322 b and the body member 322. The bore 322 a has a length that is at least as greater as its inner diameter, and, according to the example of FIGS. 23 a and 23 b, the ratio of its length to its inner diameter is approximately twenty to one. It is understood that the nozzle 320 can be secured in each cavity 252, 252, and 253 in any conventional manner.
It is understood that variations may be made in the embodiments of FIGS. 21A and 21B, 22A and 22B, and 23A and 23B. For example, the ratio of the length of the bore of each body member 302, 312, and 322 to its inner diameter set forth above is for the purposes of example only, it being understood that this ratio can be from 1:1 to 50:1. Also, the cross-section of the bores 302 c, 312 c and 322 a do not have to be constant, but can vary along their respective lengths. Further, the relative diameters of the inlet portion, the discharge portion, and the bore of the nozzle of each of the above embodiments can be varied. Still further, the threads 304 and 314 of the embodiments of FIGS. 21A and 21B, and the embodiment of FIGS. 22A and 22B can be eliminated and the body members 302, 312, and 322 can be secured in the cavities 251, 252 and 253 in any manner known in the art and can be provided with a mechanism (not shown) that enables them to be tilted relative to the axes of the cavities, as described above.
FIG. 24 depicts a graph showing a comparison of the results of the impact excavation utilizing one or more of the above embodiments (labeled “PDTI in the drawing) as compared to excavations using two strictly mechanical drilling bits—a conventional PDC bit and a “Roller Cone” bit—while drilling through the same stratigraphic intervals. The drilling took place through a formation at the GTI (Gas Technology Institute of Chicago, Ill.) test site at Catoosa, Okla.
The overall graph of FIG. 24 details the performance of the three bits though 800 feet of the formation consisting of shales, sandstones, limestones, and other materials. For example, the upper portion of the curve (approximately 306 to 336 feet) depicts the drilling results in a hard limestone formation that has compressive strengths of up to 40,000 psi.
The table below shows actual drilling data points that make up the PDTI bit drilling curve of FIG. 24. The data points shown are random points taken on various days and times. For example, the first series of data points represents about one minute of drilling data taken at 2:38 pm on Jul. 22, 2005, while the bit was running at 111 RPM, with 5.9 thousand pounds of bit weight (“WOB”), and with a total drill string and bit torque of 1,972 Ft Lbs. The bit was drilling at a total depth of 323.83 feet and its penetration rate for that minute was 136.8 Feet per Hour. The impactors were delivered at approximately 14 GPM (gallons per minute) and the impactors had a mean diameter of approximately 0.100″ and were suspended in approximately 45° GPM of drilling mud.
TORQUE WOB DEPTH PENETRATION PENETRATION
DATE TIME RPM Ft. Lbs. Lbs. Ft. FT/MIN FT/HR
Jul. 22, 2005 2:38 PM 111 1,972 5.9 323.83 2.28 136.8
1. A system for excavating a subterranean formation including a drill string having a a bit end, the system comprising:
a drill bit connected to the bit end;
a plenum formed in the drill bit that defines a plenum volume, wherein the plenum is in communication with and receives a suspension of a liquid and a plurality of impactors from the drill string;
a cavity extending from the plenum that defines a cavity volume that is less than the plenum volume so that the impactors are accelerated when flowing from the plenum to the cavity, wherein the cavity is in communication with and receives the suspension of liquid and impactors from the plenum;
a nozzle disposed in the cavity in communication with and receiving the suspension of liquid and impactors from the cavity and discharging the suspension of liquid and impactors to remove a portion of the formation; and
a junk slot formed in the drill bit to define a passage between the drill bit and a wall of a well bore in the formation, wherein the junk slot is disposed at a location on the drill bit relative to an orientation of the nozzle such that a flow of impactors discharged from the nozzle impact the formation at an angle and rebound into the passage rather than impacting the drill bit.
wherein the nozzle further comprises a bore having a substantially constant inside diameter;
and an inlet coupled to an end of the bore, the inlet having an inside diameter greater than the inside diameter of the bore.
wherein the nozzle is disposed adjacent to a longitudinal axis of the drill bit and the orientation of the nozzle is angled toward the longitudinal axis, such that the impactors discharged by the nozzle traverse the longitudinal axis.
4. The system of claim 3 wherein the nozzle is at an offset from the longitudinal axis.
a side arm cavity extending from the plenum that defines a side arm cavity volume that is less than the plenum volume so that the impactors are accelerated when flowing from the plenum to the side arm cavity, wherein the side arm cavity is in communication with and receives the suspension of liquid and impactors from the plenum;
a side arm nozzle disposed in the side arm cavity in communication with and receiving the suspension of liquid and impactors from the side arm cavity and discharging the suspension of liquid and impactors to remove a portion of the formation; and
a minor junk slot formed in the drill bit to define a minor passage between the drill bit and the inner wall of the well bore of the formation, wherein the minor junk slot is disposed at a location on the drill bit relative to an orientation of the side arm nozzle such that a flow of impactors discharged from the side arm nozzle impact the formation at an angle and rebound into the minor passage rather than impacting the drill bit.
6. The system of claim 5, wherein the side arm nozzle is disposed at an offset from the nozzle and the orientation of the side arm nozzle is angled toward the longitudinal axis.
7. The system of claim 6, wherein the offset is a vertical displacement toward a bottom surface of the well bore.
8. The system of claim 5, wherein the side arm nozzle is disposed at an offset from the nozzle and the orientation of the side arm nozzle is angled away from the longitudinal axis.
9. The system of claim 5, wherein the side arm cavity volume is less than the cavity volume such that the impactors flowing to the side arm cavity are accelerated more than the impactors flowing to the cavity volume.
10. The system of claim 5, wherein the side arm cavity volume is more than the cavity volume such that the impactors flowing to the cavity are accelerated more than the impactors flowing to the side arm cavity.
11. A method of excavating a well bore in a formation comprising:
flowing a suspension of a liquid and a plurality of solid material impactors into a plenum formed in a drill bit;
accelerating said liquid and solid material impactors as said liquid and solid material impactors flow from the plenum into a cavity extending from the plenum and through said drill bit;
discharging said liquid and solid material impactors from a nozzle disposed in the cavity ; and
contacting the formation with said liquid and solid material impactors after discharge from said nozzle,
so that a flow of the solid material impactors impact the formation at an angle and rebound into a passage defined by a disposed on the drill bit relative to an orientation of the nozzle and a wall of the well bore rather than impacting the drill bit.
12. The method of claim 11, wherein the step of discharging includes angling the nozzle such that the liquid and solid material impactors traverse the longitudinal axis.
13. The method of claim 11, further comprising accelerating said liquid and solid material impactors as said liquid and solid material impactors flow from the plenum into a side arm cavity extending from the plenum and through said drill bit.
14. The method of claim 13, further comprising discharging said liquid and solid material impactors from a side arm nozzle disposed in the side arm cavity.
15. The method of claim 14, further comprising contacting the formation with said liquid and solid material impactors after discharge from the side arm nozzle so that a flow of the solid material impactors impact the formation at an angle and rebound into a minor passage defined by a minor junk slot disposed on the drill bit relative to an orientation of the nozzle and a wall of the well bore rather than impacting the drill bit.
16. The method of 13, wherein accelerating said liquid and solid material impactors into the side arm cavity is greater than into the cavity.
17. The method of 13, wherein accelerating said liquid and solid material impactors into the cavity is greater than into the side arm cavity.
18. A drill bit for excavating a subterranean formation connected to a drill string, the drill bit comprising:
a plenum formed in the drill bit that defines a plenum volume, wherein the plenum is in communication with and receives a suspension of a liquid and a plurality of solid material impactors from the drill string;
a cavity extending from the plenum that defines a cavity volume that is less than the plenum volume so that the solid material impactors are accelerated when flowing from the plenum to the cavity, wherein the cavity is in communication with and receives the suspension of liquid and solid material impactors from the plenum;
a nozzle disposed in the cavity in communication with and receiving the suspension of liquid and solid material impactors from the cavity and discharging the suspension of liquid and solid material impactors to remove a portion of the formation; and
a junk slot formed in the drill bit to define a passage between the drill bit and a wall of a well bore in the formation, wherein the junk slot is disposed at a location on the drill bit relative to an orientation of the nozzle such that a flow of solid material impactors discharged from the nozzle impact the formation at an angle and rebound into the passage rather than impacting the drill bit.
19. The drill bit of claim 18, wherein the nozzle further comprises a bore having a substantially constant inside diameter and an inlet coupled to an end of the bore, the inlet having an inside diameter greater than the inside diameter of the bore.
20. The drill bit of claim 18 wherein the nozzle is at an offset from the longitudinal axis.
21. The drill bit of claim 18 further comprising:
a side arm cavity extending from the plenum that defines a side arm cavity volume that is less than the plenum volume so that the impactors are accelerated when flowing from the plenum to the side arm cavity, wherein the side arm cavity is in communication with and receives the suspension of liquid and solid material impactors from the plenum;
a side arm nozzle disposed in the side arm cavity in communication with and receiving the suspension of liquid and solid material impactors from the side arm cavity and discharging the suspension of liquid and solid material impactors to remove a portion of the formation; and
a minor junk slot formed in the drill bit to define a minor passage between the drill bit and the inner wall of the well bore of the formation, wherein the minor junk slot is disposed at a location on the drill bit relative to an orientation of the side arm nozzle such that a flow of solid material impactors discharged from the side arm nozzle impact the formation at an angle and rebound into the minor passage rather than impacting the drill bit.
22. The drill bit of claim 21, wherein the side arm nozzle is disposed at an offset from the nozzle and the orientation of the side arm nozzle is angled toward the longitudinal axis.
23. The drill bit of claim 22, wherein the offset is a vertical displacement toward a bottom surface of the well bore.
24. The drill bit of claim 21, wherein the side arm nozzle is disposed at an offset from the nozzle and the orientation of the side arm nozzle is angled away from the longitudinal axis.
25. The drill bit of claim 21, wherein the side arm cavity volume is less than the cavity volume such that the solid material impactors flowing to the side arm cavity are accelerated more than the solid material impactors flowing to the cavity volume.
26. The drill bit of claim 21, wherein the side arm cavity volume is more than the cavity volume such that the solid material impactors flowing to the cavity are accelerated more than the solid material impactors flowing to the side arm cavity.
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