NO20141181A1 - A vibration drilling system and tools for use in downhole drilling operations and processes for producing the same - Google Patents

Abstract

Vibration drilling tools for use coupled to a drill string in a borehole during downhole drilling operations have a tool body with a fluid flow passage extending along a longitudinal axis therethrough, a first pin end and an opposite sleeve end. A cam body portion extending longitudinally along the length of said tool has a substantially smooth, curved combat portion on an opening side having at least one elongated planar surface extending longitudinally along a closure side of the cam body portion from a tapered end to a tapered shoulder. at the sleeve end. The cam body portion, when connected to said drill string, lifts a substantially horizontal drill pipe portion of the drill string vertically into the borehole while the drill pipe portion is rotated in the borehole.

Description

A vibration drilling system and tool for downhole applications

drilling operations and method of making the same Inventor: Jeffery D. Baird

This application claims priority from provisional US patent application 61/620,043, filed Apr. 4, 2012, which is incorporated herein by reference for all purposes.

Background for the invention

Over the past twenty years, horizontal drilling technology has improved enormously with the ability to drill further into oil and gas formations. The industry's ability to uncover immeasurable oil and gas reserves for potential sale has sparked unprecedented activity in new and older oil and gas fields in the US and elsewhere. However, the ability to drill horizontally with the latest in directional control tools, new drill bit designs, advanced drilling fluid systems, etc. has still not solved the most expensive problem associated with horizontal drilling, namely "getting the cuttings out of the wellbore and maintaining a controlled weight on the drill bit". It is these two complex problems that the present invention targets.

In all deviated or horizontal wellbores, it is difficult to keep the drill cuttings from the formation suspended in the drilling fluid and prevent it from sinking out of the mud system and into the bottom of the wellbore. Many attempts have been made to keep the drill cuttings in the drilling fluid system using water-based mud, oil-based mud, synthetic mud systems and mechanical manipulation of the drill string and mud pump pressure. Further mechanical tests have been carried out with drilling tools that create extreme vibrations in the drill string through variations in drilling mud pressure. These extreme vibrations must be dampened by other tools to isolate the vibrations at the surface to prevent damage to the drilling rig and expensive directional control tools.

As the wells extend further into the formation, the ability to apply weight from the vertical portion of the drill string and transfer it through the horizontal length of the drill string to apply weight to the drill bit deteriorates. The biggest problem is that cuttings that migrate from the drill bit will fall out of the mud system and pile up at the bottom of the borehole, thereby reducing the volume capacity of the previously drilled part of the wellbore. According to industry experts, cuttings typically fall out every 20 to 30 feet. Once this accumulation takes place, other problems begin to arise. For example, narrowed hole size begins to impose extreme friction on the drill string in the lateral portion and causes increased back pressure from the returning drilling fluid penetrating into the previously drilled portions of the wellbore. Catastrophic problems can occur, including loss of circulation, swelling of the formation and fracturing of the formation. The end result of all these problems can lead to lost drill strings and loss of the wellbore.

The present invention provides a system and a tool that improves the suspension of drill cuttings in the mud system while also improving the transfer of controlled and stable weight through the lateral portion of the drill string to the drill bit. Maintenance costs are low and, more importantly, there are no moving parts in the tool itself other than the rotation of a number of cams that rotate with the drill string.

Brief description of the drawings

Figure 1A illustrates a top and rear perspective view of the present vibration tool with scraper fingers attached. Figure 1B shows a top and front perspective view of the tool in Figure 1A. Figure 2A illustrates a longitudinal section through the present vibration tool without scraper fingers.

Figure 2B shows a cross-section taken along the line A-A in Figure 1 A.

Figure 2C illustrates a top and front perspective view of an embodiment of the tool with a threaded portion along the cam body at the intersection between the cam top and a flat portion.

Figure 2D shows a side view in perspective of the embodiment in Figure 2C.

Figure 2E shows a cross-section through the embodiment in Figure 2D.

Figure 3 is a cross-sectional profile of the present vibration tool with a scraper finger inserted. Figure 4 shows a partial plan view of the large surface of the comb in the present vibrating tool with an opening to receive the scraper fingers. Figure 5A illustrates a cross-section through the tool in a borehole with the apex of the comb at the top (90-degree position) of a horizontal wellbore. Figure 5B illustrates the tool of Figure 5A rotated approximately 180 degrees in the borehole with the cam approximately at the bottom (278-degree position) of the horizontal wellbore. Figure 5C illustrates the tool of Figure 5A rotated approximately 270 degrees in the borehole with the comb approximately at the 360 degree position in the horizontal wellbore. Figures 6A-6H illustrate the movement to the center point of the tool as it is rotated, lifted and cleaned up inside the borehole. Figure 7 shows a sketch of a typical horizontal drill string in accordance with known technology. Figure 8 illustrates a sketch of a horizontal drilling operation with a drill string incorporating the present vibration tool. Figure 9 is an illustration of a rotating length of drill pipe (with the present vibration tool) being deflected inside a horizontal wellbore as the comb lifts the drill string from the bottom of the wellbore and allows critical fluid volume to act at the bottom of the wellbore and move cuttings back into the flow. Figure 10A is a top and rear perspective view of a length of standard drill pipe or heavy weight pipe having a raised wear piece retrofitted to incorporate the comb-shaped structure of the present vibratory tool. Figure 10B is a top and front perspective view of the length of standard drill pipe in Figure 10A with an elevated wear piece retrofitted to incorporate the comb-shaped structure of the present vibratory tool. Figure 10C is a cross-section through the retrofitted drill pipe in Figure 10A taken along the line A-A. Figure 11 illustrates in cross-section an alternative embodiment of the vibration tool which shows a plurality of cam elements incorporated into a single tool profile.

Detailed description of the preferred embodiment

As can be seen in the various figures, a short and uniform tool piece 20 with a unique comb-shaped profile 22 on the cam body 28 raises and lowers the drill pipe inside the borehole during rotation of the drill string (see figures 8 and 9). The cam body has a substantially smooth, smoothly curved portion along the opening side. The closing side of the comb body 28 is provided with one or more flat surfaces of varying width. This unique modification of a traditional pear-shaped cam profile on the cam body creates vibration in the drill string both vertically and horizontally approximately around the center point 112 in the borehole. The vibration is also transmitted laterally along the drill string.

Additionally, in one embodiment of the tool (Figures 2C-2E), the comb body 28 is provided with a threaded portion 200 that extends along the cutting edge 202 to the apex 42 of the comb body with a flat portion 26 of the comb body 28. The threaded portion 200 has rough and shallow threads (approximately 0.025" deep) that extend only 2" - 4" along edge 202. The threads taper as they wind toward the smaller diameter of cam body 28. The threaded portion results in the drill string being transiently driven forward toward the drill bit and ensures mechanical scraping of drill cuttings from the bottom of the wellbore when the threaded portion reaches the bottom of the wellbore during rotation.

Optimal fluid volume is maintained around the outside of the comb profile to allow drilling fluid 46 to pass by and create turbulence; and with that push the cuttings back into the mud system for removal from the well.

The cam body 28, with a substantially smooth, smoothly curved portion on the opening side 500 and flat portions 26, 34 and 36 on the closing side 502 of the cam body 28, causes an uplift of the drill string and a unique movement of the tool about the center point 112 in the borehole which creates an oscillating, harmonic rotational or vibrational movement of the drill string which will be described in more detail below (Figures 6A-6H). The threaded portion 200 along the length of the comb body further causes a transient forward pressing or jerking movement of the drill string when the edge 202 hits the cuttings at the bottom of the wellbore. The cut between flat portions 26, 31 and 36 on the cam body 28 creates several leading edges 202, 204 and 206 which cause a mechanical, step-by-step scraping of the drill cuttings at the bottom of the hole at the same time as optionally incorporated scraper fingers 24 push the drill cuttings back into the mud system without changing the bottom in the lateral wellbore.

The incorporation of short, replaceable scraper fingers 24 which can be screwed into the long flat portion 26 of the comb is made so that they do not create a "pinch point" against the wellbore.

The scraper fingers 24 can be quickly replaced on the rigging deck during trips after approximately 150 to 200 hours of operation. The flat areas on the comb profile with the leading edges 202, 204 and 206 provide an easy, systematic scraping of the bottom of the wellbore without increasing rotational friction against the drill string.

A plurality of tools 20 with comb bodies 28 installed along the drill string will create a continuous oscillation or "harmonic rotation" in the lateral portion of the drill string in the deviated or horizontal wellbore which increases turbulence in the mud system and helps prevent the drill cuttings from sinking to the bottom of the wellbore . The oscillation also improves the wellbore's stability by embedding drilling cuttings and production waste in the outer sides of the borehole wall, which forms a reinforcing, composite interface around the wellbore (figures 7, 8 and 9). This interface occurs naturally when drilling the vertical part of the well, but has not been accessible along the horizontal part before the use of the present vibration tool.

It must be understood that as the cam body 28 raises and lowers the drill string vertically in each revolution, this causes some periodic lengthening and shortening of the drill string and creates a "weight pulse effect" which helps maintain a constant sliding action for the drill string and thereby affects constant transmission of weight to the drill bit. The present vibration tool can be used with drilling speeds from 20 rpm to 130 rpm. Ideally, the best vibration effect can be achieved in the range of 40-60 rpm, but it is expected that rotational speeds of 120 rpm will not be unusual.

During installation of a vibration tool 20 of the present embodiment on the rig deck, the rotary table can be locked, and after each comb part 20 is screwed into the drill string, the position of the comb top 42 can be recorded, by referencing the degree of the apex in relation to the degrees of the rotary table. This comb tip position profile will ensure the position of all combs relative to the directional control tools when "slide operations" (moving the string without rotation of the string) are required. The profile will also make it easier to analyze and vary the extent of oscillation or the vibration potential in the lateral part. A certain leeway in the tightening facilitates positioning of the cam tops during assembly for an even distribution of cam tops in degrees from each other.

Referring to the figures and illustrations, Figure 1A shows a top and rear perspective view of the present vibration tool 20 having a cam body portion 28 having a modified pear-shaped cam profile 22. A plurality of scraper fingers 24 project outward from a first, wide planar surface 26 on the closing side of the cam body 28. The spigot end 30 of the tool 20 is opposite the socket end 32 of the tool 20. As can be seen in Figure 1A, in addition to the planar surface 26, there are also two additional planar surfaces 34 and 36, each of which may have a varying width, formed along the outside of cam body 28, each planar surface extending longitudinally from a tapered shoulder 38 at the pin end to a tapered shoulder 40 at the socket end.

It must be understood that fingers 24 may be arranged in the planar surfaces 34 and 36.

The shoulders slope gradually outward from the tool body surface 23 in the cylindrical body portion 21 to the top surface at the apex 42 of the comb-shaped body portion 28. The conical shoulders 38 and 40 provide smooth front and rear surfaces as the tool is moved longitudinally through the horizontal borehole. Figure 1B illustrates a top and front perspective view of the tool of Figure 1A. The smooth, smoothly curved portion 19 on the opening side of the cam profile 22 of the cam body 28 is clearly shown, along with the tapered shoulders 38, 40 and surface 23.

In Figures 2A and 2B, it can be seen that the tool 20 has a longitudinal axis L-L which extends along the length of the tool. The tool has a cylindrical body part 21 and a cylindrical tool body surface 23. The body part 21 has an internally threaded part 300 in the socket end 32 so that it can be connected to a first part of a drill string. An oppositely located stud end 30 has an externally threaded portion 302 for connection to another part of the drill string. The distance r1 from the tool center point 50 to the tool body surface 23 is smaller than the distance r2 from the tool center point 50 to the top point 42 of the cam body portion 28 (figure 2B). Some typical dimensions are indicated in Figure 2A. It must be understood that proportionally larger or smaller tool 20 can be produced depending on the size of the wellbore and other drilling-related requirements. Figure 2B shows a cross-section through the embodiment in Figure 2A. The various planar surfaces 26, 34 and 36 of varying width on the closing side 502 of the cam body 28 are illustrated relative to the smooth, smoothly curved portion 19 on the opening side of the cam body 28. Typical dimensions are again shown in Figure 2B. Figure 2C illustrates a top and front perspective view of an embodiment of the tool 20 with a threaded portion 200 extending along the cutting edge 202 at the apex 42 of the comb body 28 with a flat portion 26 of the comb body 28. The threaded portion 200 has coarse and shallow threads (depth approximately 0.025") which extends only 2" - 4" along the edge 202. The threads taper as they wind toward the smaller diameter of the cam body 28. The threaded portion results in the drill string being transiently driven forward toward the drill bit and provides mechanical scraping of cuttings from the bottom of the wellbore when the threaded portion reaches the bottom of the wellbore during rotation.

Furthermore, Figure 2D shows a side view in perspective of the embodiment in Figure 2C, with the threaded portion 200 along the edge of the intersection between the curved portion 19 of the cam body 28 and the flat portion 26.

Figure 2E shows a cross-section through the embodiment in Figure 2D.

A cross-section through the tool in Figure 2D is shown in Figure 2E. The threaded edge 202 is shown at the apex 42 of the cam body 28. Figure 3 shows a cross-sectional profile of the present vibration tool 20 with a scraper finger 24 inserted in the opening 27 in the planar surface 26. The fingers can be of a wire material or similar and threaded in one the end for fitting in the opening 27. Access from the rear to the openings 27a enables the insertion of a suitable wrench or other tool to tighten or loosen the fingers for insertion or replacement. Figure 4 shows a partial plan view of the large planar surface 26 of the cam body 28 of the present vibrating tool 20 with the opening 27 to receive the scraper finger 24. The openings are arranged at an angle of 30 degrees to the planar surface 26. Figure 5A illustrates a cross section through the tool 20 in a borehole with the apex 42 of the cam body 28 at the top (90-degree position) of a horizontal wellbore 43. Drilling mud 46 with suspended cuttings 48 is shown in the borehole.

It should be noted regarding Figure 5A that the tool 20 is normally at rest near the bottom of the wellbore. When the tool starts to rotate clockwise, the tool will move to the left and up the borehole. In Figure 5A, the fingers 27 are fully extended and almost touch the top of the drill hole. Also mark the center point 50 of the tool in relation to the center 112 of the wellbore. This center point 50 will move abruptly as the tool rotates and create a wobbling motion of the tool inside the borehole. The wobbling motion creates turbulence in the drilling mud and with it keeps the drill cuttings suspended in the mud. As the tool rotates, the fingers 27 sweep along the inside of the borehole and with it push the drill bit along the drill string for removal from the wellbore.

Figure 5B illustrates the tool of Figure 5A rotated approximately 180 degrees in the borehole with the comb tip 42 approximately at the bottom (278-degree position) of the horizontal wellbore. The cutting edge 204 formed along the intersection between the planar surfaces 34 and 36 moves closely along the inner wall of the borehole and causes the cuttings 48 to be set in motion and suspended in the drilling mud 46.1 figure 5B the fingers 24 have bent and sweep up the cuttings 48. The center point 50 to the tool 20 has moved upwards and to the right while the tool oscillates and rotates inside the borehole. Figure 5C illustrates the tool 20 of Figure 5A rotated approximately 270 degrees in the borehole with the cam top approximately in the 360-degree position in the horizontal wellbore. Again, the center point 50 has moved inside the drill hole and caused the tool to shift and with it create vibration in the drill string. Figures 6A-6H illustrate the movement of the center point 50 of the tool as it rotates within the borehole. The center of the borehole is shown at 112. The apex 42 of the tool is shown rotating from 12 (90 degrees) in Figure 6A to 13:30 in Figure 6B to 15:00 (180 degrees) in Figure 6C. Figure 6C shows that the tool begins to lift in the wellbore. The lift continues with the rotation of the tool as shown in Figure 6D, where the vertex 42 is shown at approximately o'clock. 4:30 p.m. When the tool has rotated to approximately 18:00 (270 degrees) a jerking movement occurs in the tool as the tool 20 with surfaces 31 and 36 falls towards the bottom of the wellbore (figure 6E) after previously being lifted. Cleaning of the cuttings along the wellbore is shown in Figures 6F-6G as the tool continues to rotate and the cutting edges 202, 204 and 206 move along the bottom of the wellbore. Figure 7 shows a sketch of a typical horizontal drill string 400 in accordance with the known technique with a mainly vertical part 402 which applies weight to the drill bit 404. The drill pipe tool couplings 406, wear piece r 408, directional control tool 405 and the drill bit 404 are shown. Tool pieces and wear pieces at the bottom of the lateral tend to limit the application of bit pressure (WOB), as shown by reference number 410. Drill cuttings fall out at approximately 1000 feet and form layers that further limit WOB, increase frictional resistance, torque, and possibly cause wedging of the pipe, which can be seen at reference numeral 412. Figure 8 shows a sketch of a horizontal drilling operation with a drill string incorporating the present vibratory tool 20 at 500 foot intervals. Penetration rates of approximately 300 feet per hour are achievable in shale formations. Figure 8 reflects that the cam tool moves the 152 meters in approximately 1 hour and 40 minutes. Furthermore, as can be seen in Figure 8, the drill string lifts and allows circulation of cuttings in a turbulent flow zone TFZ close to the tool 20. Figure 9 is an illustration of a rotating drill pipe length (with the present vibratory tool 20) being deflected inside a horizontal wellbore as the cam body 28 lifts the drill string up from the bottom of the borehole. Figure 10A is a top and front perspective view of another embodiment of the present vibratory tool 20b on a length of standard drill pipe or heavy duty casing 300 with an elevated wear piece 60. The pipe 300 is rebuilt or upgraded to incorporate a comb-shaped structure 28b which will be described with support in Figure 10C. Figure 10B is a top and rear perspective view of the length of standard drill pipe or heavy weight pipe of Figure 10A with an elevated wear piece 60 rebuilt or upgraded to incorporate the comb-shaped structure 28b of the present vibratory tool 20b. Figure 10C is a cross-section through the rebuilt drill pipe of Figure 10A taken along line 10C-10C. A cam profile element 70 is welded to the wear piece 60, together with a flat profile element 72. This creates a cam body 28b with a smooth cam portion 19a on the opening side of the cam body 28b. Other surfaces can be cut into or machined into the wear piece 60 as desired. Figure 10C also shows the inside diameter 62 of the drill pipe and a volume 46 of drilling fluid inside the wellbore 80. Figure 11 illustrates in cross-section an alternative embodiment of the vibration tool 20c and shows a plurality of cam elements 28c incorporated into a single tool profile. Although Figure 11 shows the majority of a tube wear piece 60, it will be understood that multiple chambers can be formed on a single tool as shown in the previous figures. In Figure 11, the wear piece 60 has two cam profile elements 70 and two flat elements 72 attached to the piece. Welding overlay 73 is applied and towed to create a smooth transition for the tool profile.

The following data is provided to illustrate a formula for calculating the efficiency of the vibration tool 20.

Example One (see figure 8 for explanation):

Vertical part of the well = 6000 feet.

Arc = 90 degrees @ 1000 feet.

lateral part = 4000 feet.

Well hole 6 1/8"

3 1/4" drill pipe with 4 Va tool lengths

Use of (6) vibratory tools 20 spaced 500' apart, starting 1000 feet from the drill bit and directional control tools.

50 to 60 RPM; 250 GPM; Pump pressure 1800 psi; PDC drill bit.

Friction formula for tool piece in lateral section = 3000 feet divided by an average pipe length of 31' = 96 pipe lengths. 96 pipe lengths divided by (6) tools. The tools 20 are separated by 16 pipe lengths.

Each length of tubing in the lateral section has a midsection or wear piece (DUDs) which is similar to a tool piece but is solid material and lies at the bottom of the wellbore and also causes frictional resistance. Consequently, a further 96 (DUDs) = a total of 192 (lengths) lie at the bottom of the wellbore. Each tool 20 lifts (deflects) and two opposing DUDS located 15 feet from each tool piece. (6) tools x (3) pipe lengths = (18) lengths that are transiently raised from the bottom of the wellbore at 40 to 60 times per minute (RPM). A total of 192 lengths divided by 18 (lengths) = 10.6% reduced friction force 40 to 60 times per minute.

Drill cuttings removal formula:

Each tool 20 distributes cuttings back into the mud system 40 to 60 times per minute. 96 pipe lengths divided by (6) tools 20 = 16% improved suspension of drilling cuttings and cleaning of the bottom of the wellbore.

Formula for constant weight to drill bit:

Each tool 20 placed 500 feet apart will bend the drill string by Va of one inch, (shortening and lengthening) over the length of the nearest 30 foot length of drill pipe on either side of the tool 20. Total effected length = 360 feet divided by 31' = 11, 6 lengths. A total of 96 lengths divided by 11.6 lengths = 8.27% improved weight transfer to the drill bit through weight pulse action.

Formula for vibration:

Tools 20 placed every 500 feet will rock 60 feet on each tool side. Same formula as above, where a total of 96 lengths divided by 11.6 lengths = 8.27% improvement.

Formula for whipping or oscillation:

Each tool located every 500 feet will have an effective whipping area of 60 feet on each tool side. This effect will increase the flow turbulence and pull up cuttings. Same formula as above, where 96 lengths divided by 11.6 lengths = 8.27%.

Cumulative improvement of all factors:

Total improvement of the factors in the lateral part = 51.41%

No assumptions are made in this example regarding the obvious improvements the present tool will provide in penetration rate, reduction of water loss, rig time, consumption of water and drilling fluid, hole problems, environmental impact from maintenance of oil-based systems and costs incurred, reduction of directional control runs through improved hole conditions, and other factors.

If the formulas are correct and a 51% improvement is achieved, then penetration rates will increase dramatically and cause more cuttings in the hole faster. This will obviously create a need for additional vibration tools to accommodate the inflow. Ultimately, with enough vibration tool 20 in the hole, it can be assumed that lateral drilling can be as well controlled as the vertical portion of the well.

Although the invention has been described with support in specific embodiments, the description is not intended to be understood as a limitation. Various modifications of the shown embodiments, as well as alternative embodiments of the invention, will be seen by the person skilled in the art when reading the description of the invention. It is therefore assumed that the appended claims shall cover such modifications as fall within the scope of the invention.

Claims (7)

1. Vibration drilling tool for use in a borehole during downhole drilling operations, comprising: a tool body with a fluid flow path extending along a longitudinal axis therethrough, a first pin end and an opposite socket end for connecting said tool body to a drill string; a cam body portion extending longitudinally along a length of said tool and having a substantially smooth curved cam portion on an opening side with at least one elongate planar surface extending longitudinally along a closing side of said cam body portion from a tapered shoulder at the pin end to a conical shoulder at the sleeve end, where said cam body part vertically lifts up a mainly horizontal drill pipe section in said drill string in said drill hole when said tool body is connected to said drill string and said drill pipe section is rotated in said drill hole. 2. Vibration tool according to claim 1, further comprising a threaded portion along an edge to an intersection between said curved cam portion and said at least one elongated flat surface of said cam body portion. 3. Vibration tool according to claim 1, further comprising a plurality of planar surfaces which extend in the longitudinal direction along said closing side of said cam body portion from said conical shoulder at the pin end to said conical shoulder at the socket end. 4. Vibration tool according to claim 2, where a plurality of scraping edges extend in the longitudinal direction along intersections between said planar surfaces. 5. Vibration tool according to claim 1, further comprising a plurality of scraper fingers projecting outwards from at least one of said elongated planar surfaces. 6. Vibration drilling system, comprising: a drill string for use in a borehole during downhole drilling operations, having a plurality of drill pipe lengths, a directional control tool and a drill bit, wherein at least one of said plurality of drill pipe lengths further comprises: a tool body with a fluid flow path extending along a longitudinal axis thereby, a first pin end and an opposite socket end for connecting said tool body to said drill string; a cam body portion extending longitudinally along a length of said tool and having a substantially smooth curved cam portion on an opening side with at least one elongate planar surface extending longitudinally along a closing side of said cam body portion from a tapered shoulder at the pin end to a conical shoulder at the socket end, wherein said cam body portion vertically lifts a substantially horizontal drill pipe length of said drill string vertically in said drill hole when said tool body is connected to said drill string and said drill pipe length is rotated in said drill hole 7. Method for converting a standard drill pipe length having a wear piece into a vibrating drill pipe length, comprising the steps of: producing said standard drill pipe portion having a wear piece; cleaning a surface of said wear piece for attachment of profile elements; connecting a comb-shaped profile element to said wear piece's surface; attaching a flat profile element to said wear piece's surface adjacent said comb-shaped profile element; and providing substantially smooth conical shoulders at pin and socket ends of said curved element and said flat profile element on said wear piece's surface.