WO 2013/151940 PCT/US2013/034832 1 Title: A Vibratory Drilling System and Tool For Use In Downhole Drilling Operations and A Method 2 For Manufacturing Same 3 Inventor: Jeffery D. Baird 4 This application claims priority to US Provisional Patent Application Serial No. 61/620,043 filed April 5 4, 2012, which is incorporated by reference herein for all purposes. 6 Background of the Invention 7 During the last twenty years horizontal drilling technology has improved tremendously with the 8 ability to extend farther into oil and gas formations. The ability of the industry to expose untold oil 9 and gas reserves for potential marketing has launched unprecedented activity in the new and older 10 oil and gas fields of the US and other places. Unfortunately the ability to drill horizontally with state 11 of the art steering tools, new drill bit designs, exotic drilling fluid systems, etc., have still not 12 addressed the most expensive problem in horizontal drilling, "getting the cuttings out of the 13 wellbore and maintaining a controlled amount of weight to the drill bit". It is to these two combined 14 problems that the present invention addresses. 15 Any deviated or horizontal wellbore has a problem of keeping the formation cuttings suspended in 16 the drilling fluid and from falling out of the mud system onto the bottom of the wellbore. Many 17 attempts have been made to keep the cuttings in the drilling fluid system via, water-based mud, oil 18 based mud, synthetic mud systems and mechanical manipulation of the drill string and mud pump 19 pressure. Additional mechanical attempts have been made with drilling tools that provide extreme 20 vibrations to the drill string via variations in drill mud pressures. These extreme vibrations have to be 21 cushioned by other tools to insulate the vibrations at the surface to prevent damage to the drilling 22 rig and expensive steering tools. 23 As the wells extend farther into the formation, the ability to deliver weight from the vertical section 24 of the drill string and transmit it through the horizontal length of the drill string for application of 25 weight to the drill bit is impeded. The most significant problem is that cuttings traveling from the 26 drill bit will fall out of the mud system and stack up on the bottom of the borehole thereby reducing 27 the volume capacity of the previously drilled section of the wellbore. According to some industry 28 experts, cuttings typically fall out every 20 to 30 feet. Consequently, other problems begin to occur 29 when this stacking happens. For example, restrictive hole size begins to impose extreme friction on 30 the drill string in the lateral section and causes increased back pressure from the returning drilling 31 fluid invades the previously drilled sections of the wellbore. Catastrophic problems may occur 32 including lost circulation, formation swelling, and fracturing of the formation. The end result of all 33 these issues may lead to lost drill strings and loss of the wellbore. 34 The present invention provides a system and tool that improves cuttings suspension in the mud 35 system while improving the transition of controlled and steady weight through the lateral section of 36 the drill string to the drill bit. Refurbishing costs are low and, more importantly, there are no moving 37 parts in the tool itself other than the rotation of the number of cams rotating with the drill string. 38 1 39 WO 2013/151940 PCT/US2013/034832 1 Brief Description of the Drawings 2 Fig. 1A illustrates a top, rear perspective view of the present vibratory tool with wiping fingers 3 attached. 4 Fig. 1B shows a top, front perspective view of the tool of Fig. 1A. 5 Fig. 2A illustrates a side elevation, cross-sectional view of the present vibratory tool without wiping 6 fingers. 7 Fig. 2B shows a cross-sectional view taken along line A-A of Fig. 1A. 8 Fig. 2C illustrates a top, front perspective view of an embodiment of the tool with a threaded portion 9 along the cam body at the cam apex intersection with a flat section. 10 Fig. 2D shows a side elevation perspective view of the embodiment of Fig. 2C 11 Fig. 2E shows a cross-sectional view of the embodiment of Fig. 2D. 12 Fig. 3 is a cross-sectional end view of the present vibratory tool with a wiping finger installed. 13 Fig. 4 shows a partial, top plan view of the large flat on the cam of the present vibratory tool with 14 opening to receive the wiping fingers. 15 Fig. 5A illustrates a cross-sectional view of the tool in a borehole with the apex of the cam at the top 16 (90 degree position) of a horizontal wellbore. 17 Fig. 5B illustrates the tool of Fig. 5A rotated about 180 degrees in the borehole with the cam at 18 approximately the bottom (278 degree position) of the horizontal wellbore. 19 Fig 5C illustrates the tool of Fig. 5A rotated about 270 degrees in the borehole with the cam at 20 approximately the 360 degree position of the horizontal wellbore. 21 Figs. 6A-6H illustrate the displacement of the center point of the tool as it rotates, lifts, and cleans 22 within the borehole. 23 Fig. 7 shows a sketch of a typical prior art horizontal drill string. 24 Fig. 8 illustrates a sketch of a horizontal drilling operation with a drill string incorporating the present 25 vibratory tool. 26 Fig. 9 is an illustration of a rotating drill pipe section (with the present vibratory tool) deflecting 27 within a horizontal wellbore as the cam lifts the drill string from the bottom of the borehole allowing 28 critical fluid volume to effect the bottom of the wellbore and move cuttings back into the flow 29 stream. 30 2 31 WO 2013/151940 PCT/US2013/034832 1 Fig. 10A is a top, rear perspective view of a section of standard drill pipe or heavy weight pipe having 2 a raised wear joint retrofitted to incorporate the cam-shaped structure of the present vibratory tool. 3 Fig 10B is a top, front perspective view of the section of standard drill pipe of Fig. 10A having a raised 4 wear joint retrofitted to incorporate the cam-shaped structure of the present vibratory tool. 5 Fig. 10C is a cross-sectional view of the retrofitted drill pipe of Fig 10A taken along line A-A. 6 Fig. 11 illustrates in cross-section an alternative embodiment of the vibratory tool showing a 7 plurality of cam elements incorporated into a single tool profile. 8 Detailed Description of the Preferred Embodiment 9 As may be seen in the various Figures, a short and single body tool joint 20 with a unique cam 10 shaped profile 22 on the cam body 28 which raises and lowers the drill pipe within the borehole 11 during drill string rotation. (See Figs.8 and 9.) The cam-body has a generally smooth, consistent, arc 12 section along the opening side. The closing side of the cam body 28 is provided with one or more 13 flat surfaces of varying widths. This unique modification of a traditional pear-shape cam profile on 14 the cam body creates vibratory action of the drill string both vertically and horizontally generally 15 about the center point 112 of the borehole. The vibratory action is also transmitted laterally along 16 the drill string. 17 Additionally, in one embodiment of the tool (Figs 2C-2E), the cam body 28 is provided with a 18 threaded portion 200 extending along the intersecting edge 202 of the apex 42 of the cam body with 19 a flat section 26 of the cam body 28. The threaded portion 200 has course and shallow threads 20 (depth approximately 0.025") that extend only 2"-4" along edge 202. The threads thin out as they 21 spiral toward the smaller diameter of the cam body 28. The thread portion results in momentary 22 forward urging of the drill string toward the drill bit and provides mechanical scrapping of cuttings 23 from the bottom of the wellbore when the threaded portion reaches the bottom of the well bore 24 during rotation. 25 Optimum fluid volume is maintained around the outside of the cam profile to allow drilling fluid 46 26 to pass and create turbulence; therefore, thrusting cuttings back into the mud system for 27 evacuation. 28 The cam body 28 with a generally, smooth, consistent opening side 500 arc section and flat sections 29 26, 34, and 36 on the closing side 502 of the cam body 28 causes a lifting of the drill string and a 30 unique displacement of the tool center point 112 of the borehole creating an oscillating, harmonic 31 rotation, or vibratory motion of the drill string as will be described further below (Figs. 6A-6H). The 32 threaded portion 200 along the length of the cam body further causes a momentary, forward-urging 33 or lurching of the drill string when the edge 202 reaches the bottom cuttings in the wellbore. 34 The intersection of flats 26, 31, and 36 on the cam body 28 provide several leading edges 202, 204, 35 and 206 to cause a mechanical, stepped scraping of the cuttings on the bottom of the hole while 36 optional wiping fingers 24 thrust the cuttings back into the mud system without altering the bottom 37 of the lateral wellbore. 38 3 WO 2013/151940 PCT/US2013/034832 1 The incorporation of short replaceable wiping fingers 24 that may be threaded into the long flat 26 2 on the cam are positioned such that they do not create a "pinch point" with the wellbore. 3 The wiping fingers 24 may be quickly replaced on the rig floor during trips after approximately 150 to 4 200 hours of operation. The flat areas of the cam profile with the leading edges 202, 204, and 206, 5 provide a gentle systematic scrapping of the bottom of the well bore without adding additional 6 rotational friction to the drill string. 7 A plurality of tools 20 with cam bodies 28 installed along the drill string will create a continuous 8 oscillation or "harmonic rotation" of the lateral section of the drill string in the deviated or 9 horizontal wellbore which improves the turbulence of the mud system and helps keep the cuttings 10 from dropping out onto the bottom of the wellbore. The oscillation also improves well bore stability 11 by imbedding cuttings and debris into the outer sides of the wall of the borehole forming a 12 strengthening, composite boundary layer around the wellbore (Figs. 7, 8, and 9). This boundary 13 layer naturally occurs when drilling the vertical section of the well but has not been available along 14 the horizontal section until the utilization of the present vibratory tool. 15 It should be understood that as the cam body 28 raises and lowers the drill string vertically every 16 revolution this causes an intermittent lengthening and shortening of the drill string length to some 17 degree and creates a "weight pulse effect" that helps maintain a constant sliding action of the drill 18 string, thereby, influencing constant transmission of weight to the drill bit. The present vibratory 19 tool may be utilized with drilling speeds from 20 rpm to 130 rpm. Ideally best vibratory action may 20 be achieved in the 40--60 rpm range, but it is anticipated that rotation rates of 120 rpm may not be 21 uncommon. 22 During installation of a vibratory tool 20 of the present design at the rig floor, the rotary table may 23 locked and after torqueing each cammed section 20 into the drill string, the position of the cam apex 24 42 may be recorded, referencing the degree of the apex to the degrees of the rotary table. This cam 25 apex position profile will insure the position of all the cams in relation to the steering tools when 26 there is the need for "sliding" operations (moving the string without rotation of the string). The 27 profile will also help analyze and vary the amount of oscillation or vibratory potential of the lateral 28 section. Some range of torqueing ability helps to position the cam apexes during assembly for an 29 even distribution of cam apexes in degrees from each other. 30 Turning to the figures and illustrations, Fig.1A shows a top, rear perspective view of the present 31 vibratory tool 20 having a cam body portion 28 with a modified pear-shaped cam profile 22. A 32 plurality of wiping fingers 24 extend outwardly from a first, wide flat surface 26 on the closing side of 33 the cam body 28. The pin end 30 of the tool 20 is opposite the box end 32 of the tool 20. As may be 34 seen in Fig. 1A, in addition to flat surface 26, two other flat surfaces 34 and 36 each of which may 35 have a varying width are formed along the outer surface of the cam body 28 each flat surface 36 extending longitudinally from pin end tapering shoulder 38 to box end tapering shoulder 40. 37 4 38 WO 2013/151940 PCT/US2013/034832 1 It should be understood that fingers 24 may be provided in the flat surfaces 34 and 36 2 The shoulders gradually taper from the tool body surface 23 of the cylindrical body portion 21 to the 3 top surface at the apex 42 of cam-shaped body portion 28. The tapering shoulders 38 and 40 4 provide smooth leading and trailing surfaces as the tool is moved longitudinally through the 5 horizontal borehole. 6 Fig. 1B illustrates a top, front perspective view of the tool of Fig. 1A. The smooth, consistent, 7 opening side arc section 19 of the cam profile 22 on the cam body 28 is clearly illustrated as are the 8 tapering shoulders 38, 40 and surface 23. 9 Turning to Figs. 2A and 2B, it may be seen that the tool 20 has a longitudinal axis L-L running the 10 length of the tool. The tool has a cylindrical body portion 21 and a cylindrical tool body surface 23. 11 The body portion 21 has an internally threaded section 300 at the box end 32 so that it may be 12 coupled to a first drill string section. An opposite, pin end 30 has an externally threaded section 302 13 for coupling to another section of the drill string. The distance r1 from the tool center point 50 to 14 the tool body surface 23 is less than the distance r2 from the center point 50 of the tool to the apex 15 42 of the cam body portion 28 (Fig. 2B). Some typical dimensions are noted on Fig. 2A. It should be 16 understood that proportionally larger or small tools 20 could be made depending on the size of the 17 wellbore and other drilling requirements. 18 In Fig. 2B a cross-sectional view of the embodiment of Fig. 2A is shown. The various flat surfaces 26, 19 34, and 36 of varying widths on the closing side 502 of the cam body 28 are illustrated in relation to 20 the smooth, consistent arc section 19 on the opening side of cam body 28. Typical dimensions are 21 again provided on Fig. 2B. 22 Fig. 2C illustrates a top, front perspective view of an embodiment of the tool 20 with a threaded 23 portion 200 extending along the intersecting edge 202 at the apex 42 of the cam body 28 with a flat 24 section 26 of the cam body 28. The threaded portion 200 has course and shallow threads (depth 25 approximately 0.025") that extend only 2"-4" along edge 202. The threads thin out as they spiral 26 toward the smaller diameter of the cam body 28. The thread portion results in momentary forward 27 urging of the drill string toward the drill bit and provides mechanical scrapping of cuttings from the 28 bottom of the wellbore when the threaded portion reaches the bottom of the well bore during 29 rotation. 30 Additional Fig. 2D shows a side elevation perspective view of the embodiment of Fig. 2C with the 31 threaded portion 200 along the edge of the intersection of the cam arc section 19 of the cam body 32 28 and the flat section 26. 33 Fig. 2E shows a cross-sectional view of the embodiment of Fig. 2D. 34 A cross sectional view of the tool of Fig. 2D is shown in Fig. 2E. The threaded edge 202 is shown at 35 the apex 42 of the cam body 28. 36 5 37 WO 2013/151940 PCT/US2013/034832 1 Fig. 3 shows a cross-sectional end view of the present vibratory tool 20 with a wiping finger 24 2 installed in opening 27 in flat surface 26 The fingers may be of wire cable material of the like and 3 threaded on one end for retention in opening 27. The rear access of the openings 27a allows a 4 suitable wrench or tool to be inserted to tighten or loosen the fingers for installation or 5 replacement. 6 Fig. 4 shows a partial, top plan view of the large flat surface 26 on the cam body 28 of the present 7 vibratory tool 20 with opening 27 to receive the wiping finger 24. The openings are set at a 30 8 degree angle to the face of the flat 26. 9 Fig. 5A illustrates a cross-sectional view of the tool 20 in a borehole with the apex 42 of the cam 10 body 28 at the top (90 degree position) of a horizontal wellbore 43. Drilling mud 46 with suspended 11 cuttings 48 is shown in the borehole. 12 It should be noted in Fig. 5A that the tool 20 is generally resting near the bottom of the wellbore. As 13 the tool begins to rotate clockwise, the tool will shift left and upwardly in the borehole. In Fig. 5A 14 the fingers 27 are fully extended and almost touch the top side of the borehole. Further, note the 15 center point 50 of the tool in relation to the center 112 of the wellbore. This center point 50 will 16 move abruptly as the tool rotates creating a shifting movement of the tool within the borehole. The 17 shifting motion creates turbulence in the drilling mud keeping the cuttings suspended in the mud. 18 As the tool rotates, the fingers 27 sweep inside the borehole thereby thrusting the cuttings along the 19 drill string for evacuation. 20 Fig. 5B illustrates the tool of Fig. 5A rotated about 180 degrees in the borehole with the cam apex 42 21 at approximately the bottom (278 degree position) of the horizontal wellbore. The intersecting edge 22 204 formed along the intersection of flat surfaces 34 and 36 moves closely along the inner wall of 23 the borehole and causes cuttings 48 to be displaces and suspended in the drilling mud 46. In Fig. 5B 24 the fingers 24 have flexed and are sweeping cuttings 48. The center point 50 of the tool 20 has 25 moved upwardly and to the right as the tool oscillates and rotates within the borehole. 26 Fig 5C illustrates the tool 20 of Fig. 5A rotated about 270 degrees in the borehole with the cam apex 27 at approximately the 360 degree position of the horizontal wellbore. Again the center point 50 has 28 moved within the borehole causing the tool to shift creating vibration in the drill string. 29 Figs. 6A-6H illustrate the displacement of the center point 50 of the tool as it rotates within the 30 borehole. The center of the borehole is shown at 112. The apex 42 of the tool is shown rotating 31 from 12 o'clock (90 degrees) in Fig. 6A through 1:30 o'clock in Fig. 6B to 3:00 o'clock (180 degrees) in 32 Fig. 6C. Fig. 6C shows that the tool beginning to lift in the wellbore. The lifting continues with the 33 rotation of the tool as seen in Fig. 6D where the apex 42 is shown at about 4:30 o'clock. When the 34 tool has rotated to about 6:00 o'clock (270 degrees) a jarring of the tool is created as the tool 20 35 with flats 31 and 36 falls toward the wellbore bottom (Fig. 6E) after having been earlier lifted. 36 Cleaning of the cuttings along the wellbore is shown in Figs. 6F-6G. as the tool continues to rotate 37 and intersecting edges 202, 204, and 206 move along the bottom of the wellbore. 38 6 39 WO 2013/151940 PCT/US2013/034832 1 Fig. 7 shows a sketch of a typical prior art horizontal drill string 400 with a generally vertical section 2 402 that applies weight to the drill bit 404. Drill pipe tool connections 406, wear joints 408, steering 3 tools 405, and the drill bit 404 are shown. Tool joints and wear joints on the bottom of the lateral 4 tend to restrict delivery of weight to drill bit (WOB) as shown at numeral 410. Cuttings fall out at 5 approximately 1000 feet forming beds that further restrict WOB, add drag, torque, and possible pipe 6 sticking as seen at numeral 412. 7 Fig. 8 illustrates a sketch of a horizontal drilling operation with a drill string incorporating the present 8 vibratory tool 20 at 500' intervals. Penetration rates of approximately 300' per hour are achievable 9 in shale formations. Fig. 8 reflects that the cam tool travels the 500' in approximately 1 hour 40 10 minutes. Further, as may be seen in Fig. 8, the drill string lifts and allows for cuttings to be circulated 11 in a turbulent flow zone TFZ in the proximity of the tool 20. 12 Fig. 9 is an illustration of a rotating drill pipe section (with the present vibratory tool 20) deflecting 13 within a horizontal wellbore as the cam body 28 lifts the drill string from the bottom of the borehole. 14 Fig. 10A is a top, front perspective view another embodiment of the present vibratory tool 20b on a 15 section of standard drill pipe or heavy weight pipe 300 having a raised wear joint 60. The pipe 300 is 16 retrofitted or refurbished to incorporate a cam-shaped structure 28b as will be described in Fig. 10C. 17 Fig 10B is a top, back perspective view of the section of standard drill pipe or heavy weight pipe of 18 Fig. 10A having a raised wear joint 60 retrofitted or refurbished to incorporate the cam-shaped 19 structure 28b of the present vibratory tool 20b. 20 Fig. 10C is a cross-sectional view of the retrofitted drill pipe of Fig 10A taken along line 10C-10C. A 21 cam profile member 70 is welded to the wear joint 60 as is a flat profile member 72.This creates a 22 cam body 28b with a smooth, cam section 19a on the opening side of the cam body 28b Other flats 23 may be cut or machined in the wear joint 60 as appropriate. Fig. 10C also shows the drill pipe inside 24 diameter 62 and a drilling fluid volume 46 within the wellbore 80. 25 Fig. 11 illustrates in cross-section an alternative embodiment of the vibratory tool 20c showing a 26 plurality of cam elements 28c incorporated into a single tool profile. While Fig. 11 shows the 27 plurality on a pipe wear joints 60, it is understood that multiple cams may be formed on a single tool 28 as shown in earlier figures. In fig. 11, the wear joint 60 has two cam profile members 70 and two flat 29 members 72 affixed to the joint. Weld build ups 73 are applied and ground to create a smooth 30 transition of the tool profile. 31 7 32 WO 2013/151940 PCT/US2013/034832 1 The following data is provided to illustrate a formula to calculate the effectiveness of the vibratory 2 tool 20. 3 Example One (refer to Fig. 8 for understanding): 4 Vertical Section of the well= 6,000 ft. 5 Curve= 90 degrees @1000 ft. 6 Lateral Section= 4,000 ft. 7 6 1/8" Wellbore 8 3 Y 2 " Drill Pipe with 4 %" Tool Joints 9 Using (6) vibratory tools 20 spaced 500' apart, beginning 1,000 ft. from the drill bit and steering 10 tools. 11 50 to 60 RPMs; 250 GPMs; 1,800 PSI Pump Pressure; PDC Drill Bit. 12 Lateral Section Tool Joint Friction Formula = 3,000 ft. divided by 31' average joint length = 96 joints. 13 96 joints divided by (6) tools. Tools 20 spaced every 16 joints. 14 Each lateral joint of pipe has a middle section or wear joint (DUDs) that resembles a tool joint but is 15 solid material and is lying on the bottom of the wellbore also causing drag. So, additional 96 (DUDs) 16 = 192 total (joints) lying on the bottom of the wellbore. Each tool 20 raises itself, (deflects) and two 17 opposing DUDS which are 15 ft. from each torqued tool joint. (6) tools X (3) joints= (18) joints that 18 are momentarily raised from the bottom of the well bore 40 to 60 time per minute, (RPMs). 192 19 total joints divided by 18 (joints) = 10.6% reduced drag 40 to 60 times per minute. 20 Cutting Removal Formula: 21 Each tool 20 distributes cuttings back into the mud system 40 to 60 times per minute. 96 Joints 22 divided by (6) tools 20 = 16% cuttings suspension improvement and cleans the bottom of the well 23 bore. 24 Constant Weight to Bit Formula: 25 Each tool 20 positioned 500 ft. apart will deflect drill string % of an inch, (shortening and 26 lengthening) the length of immediate 30 ft. section of drill pipe either side of the tool 20. Total 27 effected length = 360 ft. divided by 31'= 11.6 joints. 96 total joints divided by 11.6 joints = 8.27% 28 improved weight transmission to drill bit by weight pulse action. 29 Vibration Formula: Tools 20 placed every 500 ft. will rock 60 ft. each side of tool. Same formula as 30 above wherein 96 total joints divided by 11.6 joints =8.27% improvement. 31 Whipping or Oscillation Formula: Each tool placed every 500 ft. will have an effective whipping area 32 of 60 ft. each side of tool. This action will increase fluid turbulence to pick up cuttings. Same formula 33 as above wherein 96 joints divided by 11.6 joints= 8.27%. 34 8 35 WO 2013/151940 PCT/US2013/034832 1 Accumulative improvement on all issues: 2 Friction....................... 10.6% 3 Cutting Removal....... 16% 4 Constant Weight....... 8.27% 5 Vibration.................... 8.27% 6 Whipping Formula... 8.27% 7 Total Lateral Issues Improvement = 51.41% 8 No assumptions have been made in this example pertaining to the obvious improvements the 9 present tool will effect penetration rates, reduction in water loss, rig time, water and drilling fluid 10 usage, hole problems, environmental impact of oil based system maintenance and the expenses 11 incurred, reduction of steering runs by improved hole conditions, and other issues. 12 If formulas are correct and 51% improvement is achieved then penetration rates will improve 13 dramatically causing more cuttings in the hole quicker. This would give obvious need for additional 14 vibratory tools to accommodate the influx. Ultimately, with enough vibratory tools 20 in the hole, it 15 may be assumed that lateral drilling may become as controlled as the vertical section of the well. 16 Although the invention has been described with reference to specific embodiments, the description 17 is not meant to be construed in a limited sense. Various modifications of the disclosed 18 embodiments, as well as alternative embodiments of the invention will become apparent to persons 19 skilled in the art upon the reference to the description of the invention. It is, therefore, 20 contemplated that the appended claims will cover such modifications that fall within the scope of 21 the invention. 22 9 23