WO2014039078A1 - Apparatus and method for lateral well drilling - Google Patents
Apparatus and method for lateral well drilling Download PDFInfo
- Publication number
- WO2014039078A1 WO2014039078A1 PCT/US2013/000209 US2013000209W WO2014039078A1 WO 2014039078 A1 WO2014039078 A1 WO 2014039078A1 US 2013000209 W US2013000209 W US 2013000209W WO 2014039078 A1 WO2014039078 A1 WO 2014039078A1
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- WO
- WIPO (PCT)
- Prior art keywords
- drive
- segment
- face
- base plane
- rotation
- Prior art date
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- 238000005553 drilling Methods 0.000 title description 29
- 238000005520 cutting process Methods 0.000 claims abstract description 145
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Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/20—Flexible or articulated drilling pipes, e.g. flexible or articulated rods, pipes or cables
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B29/00—Cutting or destroying pipes, packers, plugs, or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windows; Deforming of pipes in boreholes or wells; Reconditioning of well casings while in the ground
- E21B29/06—Cutting windows, e.g. directional window cutters for whipstock operations
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B7/00—Special methods or apparatus for drilling
- E21B7/04—Directional drilling
- E21B7/046—Directional drilling horizontal drilling
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B7/00—Special methods or apparatus for drilling
- E21B7/04—Directional drilling
- E21B7/06—Deflecting the direction of boreholes
- E21B7/061—Deflecting the direction of boreholes the tool shaft advancing relative to a guide, e.g. a curved tube or a whipstock
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B3/00—Rotary drilling
- E21B3/02—Surface drives for rotary drilling
- E21B3/022—Top drives
Definitions
- present invention relates to an apparatus and method for rotating a shaft around a radius using a flexible splined member.
- the invention relates to an apparatus and method for mechanically cutting earthen formation surrounding a wellbore, and optionally, cutting the casing and/or cement disposed in the wellbore, with the use of said flexible spline member.
- a multitude of wellbores have been drilled into earth strata for the extraction of oil, gas, and other material therefrom.
- Such wells are found to be initially unproductive, or may decrease in productivity over time, even though it is believed that the surrounding strata still contains extractable oil, gas, water or other material.
- Such wells are typically vertically extending holes including a production casing, usually of a mild steel pipe, having an outer diameter of a few inches to over 12 inches and used for the transportation of the oil, gas, or other material upwardly to the earth's surface.
- Commonly employed production casing sizes range from about 4.5" to 9.0" and account for an estimated 97%+ of the wells in the world.
- the wellbore may be uncased at the zone of interest, commonly referred to as an "openhole" completion.
- a hole in cased wells can be produced by punching a hole in the casing, abrasively cutting a hole in the casing, milling a hole in the casing wall, milling out a vertical section of casing, or thermally or chemically forming a hole in the casing. While more or less efficacious, such methods are generally familiar to those in the art.
- a type of whipstock having a lower radius is typically incorporated to direct the cutting head out of the wellbore and into the formation.
- the whipstock is often set on the end of upset tubing (production tubing) and secured in place by a packer or anchor.
- Certain whipstock configurations are able to direct cutting tools outside of the wellbore while themselves staying within the wellbore; other, typically more complicated systems involve various mechanisms that extend outside of the wellbore.
- the cutting tools are run on the end of coiled tubing.
- the cutting tool completes its transition to the horizontal direction over a radius of about 100 feet. It is common for horizontal drilling providers to speak of their "build angle", which commonly range from around 3.5 degrees per foot to about 0.35 degrees per foot. Translating such a system around 90 degrees may thus require between about 25 feet and about 250 feet.
- the size of this transition radius stems primarily from the length, diameter and effective rigidity of the cutting system's components that must transition around the radius.
- the present invention is an apparatus for cutting laterally into an earthen formation from a wellbore that includes a flexible spline member formed from a series of meshable drive segments, wherein the drive segments collectively form at least one inner passageway.
- the flexible spline member being sized and configurable such that an attached cutting head assembly, the at least one inner passageway, and a fluid pumping source may be in fluid communication.
- the flexible spline member further having certain acute angles on the teeth, thereby allowing the segments to remain splined, even while transmitting high torque around a tight radius.
- a first flexible spline member end portion is sized and configured to be attachable to a rotation means, such as a motor, and a second flexible spline member end portion operatively coupled to a cutting head assembly such that torque applied to the first flexible spline member end portion by the rotational source may be translated to the cutting head assembly by virtue of the drive segments.
- a rotation means such as a motor
- a second flexible spline member end portion operatively coupled to a cutting head assembly such that torque applied to the first flexible spline member end portion by the rotational source may be translated to the cutting head assembly by virtue of the drive segments.
- a method for forming a lateral borehole using a downhole tool assembly operatively connected to a rotational source the rotational source being coupled to a conduit, such that the conduit, rotational source, and downhole tool assembly are in fluid communication.
- the method further includes activating the rotational source so that torque applied to the drive segments that form the flexible spline member is thereby translated to the cutting head of the downhole tool assembly, causing the cutting head to rotate.
- a tubular member disposed within the flexible spline member's inner passageway (at least one inner passageway); this tubular member being capable of providing a substantially leak-proof fluid conduit between the pumping source and the cutting head assembly.
- the substantially leak-proof fluid conduit can be created by utilizing a hose, flexible tubing, KEVLAR ® , convoluted tubing, interlocking hose or similar conduit.
- the apparatus can include a rotational source selected from a downhole fluid-driven or electrical motor, a top-drive motor or some combination thereof.
- the apparatus has an inherent tensioning system that when under a torsional load pulls the segments together on account of the functioning drive angle geometry (i.e. the angles on the drive and driver faces).
- the apparatus may include another tensioning means used to hold the drive segments together such as by a tensioning line.
- the tensioning line may be useful when tripping into the wellbore (i.e. when torsional resistance is usually low) or in the event of a rotational system failure. As such the tension line may serve as a sort of secondary or back-up tensioning means.
- the apparatus may also include a retrieval means suitable not only for typical retrieval/pulling-out of the drill-string from the borehole, but also suitable for "hard" over-pulls, such as if the system should become firmly stuck.
- the drive segments may be held in tension by the placement of a preload on a wire(s) (tension line) running through the series of drive segments.
- the same tensioning line used as the secondary or back-up tensioning means may be used for the retrieval of the drill-string.
- the cutting head assembly has at least one cutting surface and is configured to mechanically cut into the earthen formation.
- the cutting head assembly has at least one orifice for the ejection of fluid thereof and is capable of being in fluid communication with the fluid pumping source. Ejecting of the fluid from on or near the cutting head has one or more of the following purposes: to keep the cutting head clean for effective cutting, keep the cutting head cool to protect coatings, bonding-agents and/or PDC inserts, emitting chemicals for treating the formation or pre-disposing the formation to more efficient cutting, and emitting fluid to provide a suitable medium to carry formation cuttings back toward the wellbore.
- the drive segments have grooves or flats about their exterior. Such designs assure the removal of cuttings by providing a "wide" fluid and cuttings return flow path around the exterior of the drive segments.
- the series of drive segments (two or more) have an outer profile that is generally cylindrical or barrel-shaped (wider in the middle than at the ends).
- a barrel shape outer profile (that at its maximum is of the same diameter as the cutting head) used in conjunction with flats on the webbing (described below), yields a highly efficient cuttings return path while also mitigating helical buckling.
- each drive segment has a base plane situated perpendicular to the axis of rotation of that drive segment; said base plane being situated at or near the center of said drive segment.
- Each drive segment has at least one tooth or projection (male) positioned on each side of this base plane and has at least one socket (female) positioned on each side of the base plane.
- the at least one tooth on one side of the base plane being distinct from the at least one tooth (or projection) on the other side of the base plane; and, the at least one socket on one side of the base plane being distinct from the at least one socket on the other side of the base plane.
- the at least one tooth on one side of the base plane of a drive segment mesh into at least one mating socket on an adjacent drive segment.
- this disclosure In operation (e.g. rotating while articulated), a given tooth will mesh into and out of a socket— hence the drive segments of this disclosure is a sort of gear (which have meshing teeth and sockets). However, operationally, this disclosure is also like a spline in that torque is transmitted from the same tooth to the same socket. On account of these features the devices is sometimes herein referred to as flexible spline member.
- the apparatus can include a whipstock, optionally positioned on the end of upset tubing, and used to guide the drive segments around a radius.
- the whipstock can include a passageway through which formation cuttings can pass to a location below the whipstock.
- An embodiment of the present invention is a method for cutting laterally, or generally perpendicular, into an earthen formation from a wellbore utilizing the apparatus described above.
- An embodiment of the present invention is a method for cutting laterally into an earthen formation from a wellbore by guiding a downhole tool assembly having a series of drive segments, defining at least one inner passageway, through a channel defined by a guide assembly and positioning the downhole tool assembly so that the downhole tool assembly contacts a portion of the earthen formation to be laterally cut.
- the downhole tool assembly is coupled to a conduit, such that the conduit and downhole tool assembly are in fluid communication.
- the method further includes pumping one or more fluids through the conduit and into the downhole tool assembly, rotating a cutting head of the downhole assembly and cutting a borehole into the earthen formation with the cutting head in a direction lateral to the wellbore.
- the downhole tool assembly can be operatively connected to a rotational source and the rotational source is coupled to a conduit, such that the conduit, rotational source, and downhole tool assembly are in fluid communication.
- the method further can include activating the rotational source, wherein a torque is applied to the drive segments comprising a flexible tubular member and translating the torque to a cutting head of the downhole tool assembly, wherein the torque causes the cutting head to rotate.
- the rotational source can be activated by the fluid flow through the conduit into the rotational source.
- the drive segments collectively define at least one inner passageway
- the downhole tool assembly further includes one or more orifices in fluid communication with at least a portion of a tubular member disposed within the inner passageway, wherein the method further includes pumping one or more fluids through the tubular member and emitting the pumped fluid from the one or more orifice, whereby the fluid contacts the cutting head.
- the system may be deployed by a variety of oilfield work-over units including: Coiled Tubing, E-Line or Slick-Line, or via a Top-Drive.
- Figure 1 illustrates a cross-sectional view of a cased wellbore containing a whipstock, wherein an embodiment of the present invention is deployed in the wellbore, guided through a guide channel in the whipstock, and has created a lateral borehole through the casing and cement and is proceeding into an earthen formation.
- Figure 2 illustrates a cross-sectional view of a cased wellbore containing a whipstock, wherein an embodiment of the present invention is deployed in the wellbore, guided through a guide channel in the whipstock, and has created a lateral borehole through the casing and into the cement and is approaching an earthen formation.
- Figure 3 illustrates a cross-sectional view of an openhole completed wellbore containing a whipstock prior to the use of the whipstock in conjunction with an embodiment of the present invention.
- Figures 4a— 4d illustrate various views of a drive segment consistent with an embodiment of the present invention.
- Figures 5a - 5d illustrate various views of a drive segment consistent with an embodiment of the present invention.
- Figure 6 illustrates a laid open side view of a drive segment consistent with an embodiment of the present invention.
- Figure 7 illustrates a laid open side view of a drive segment consistent with an embodiment of the present invention.
- Figures 8a - 8b illustrate various views of a drive segment consistent with an embodiment of the present invention.
- an apparatus for cutting laterally from a wellbore is provided.
- lateral or “laterally” refers to a borehole deviating from a wellbore and/or a direction deviating from the orientation of the longitudinal axis of the wellbore.
- orientation of the longitudinal axis of the wellbore may vary as the depth of the well increases, and/or specific formations are targeted and as wells are varied from vertical to deviated wells and to substantially horizontal wells.
- strata refers to the subterranean formation also referred to as "earthen formation.”
- a particular earthen formation is typically chosen due to the properties of the formation relating to hydrocarbons; such a formation may be referred to as an "earthen formation of interest”.
- the present invention relates to an apparatus, system, and method for cutting laterally into an earthen formation.
- the apparatus may be used for cutting laterally into casing and/or cement disposed within a wellbore.
- the apparatus may be used to cut laterally through the casing, cement and earthen formation, which is advantageous in that the number of required downhole trips can be significantly reduced.
- the apparatus may be used either in cased wellbores or in openhole wellbores.
- the apparatus may be used in wellbores wherein one or more holes have already been created through the casing and/or cement.
- the apparatus is a flexible, segmented spline tool capable of providing torque around a tight radius.
- the apparatus is a downhole tool comprising a cutting head assembly and the above "flexible spline member" attached to a means of rotation and in fluid communication with a pumping source.
- one end portion, or first end portion, of a conduit (e.g. a pipe, hose or tubing) run into the wellbore is coupled to a fluid pumping source; and, the second end portion of the conduit is coupled to the first end portion of the flexible spline member, such that the fluid pumping source is in fluid communication with the flexible spline member and attached cutting head assembly.
- the fluid pumping source can be any conventional fluid pump capable of providing fluid pressures to the downhole tool assembly such that the downhole tool assembly is able to emit fluid from near or on the cutting head.
- the fluid may be emitted at a pressure from about 100 to 5000 psi.
- the fluid may be pumped at a pressure from about 5,000 to about 10,000 psi.
- suitable flow rate for the fluid may range from an equivalent of about 3 to about 12 gallons per minute (gpm), while in other embodiments, the operating flow may range from about 10 to about 25 gpm; while in yet other applications (typically larger diameter and/or longer borehole drilling applications), the operating flow range may exceed 25gpm.
- Non-limiting examples of the fluid pumped from the fluid pumping source include nitrogen, nitrogen-fluid mixture, air, foam, diesel, hydrochloric acid, water, formation brine, biocides, wettability modifiers, surfactants, and the like.
- fluid pumped through orifices on or near the cutting head assembly can be used to eject chemicals from the drill-string to better pre-dispose the formation to mechanical cutting and/or to diffuse a chemical treatment(s) into the formation adjacent to the lateral borehole (e.g. biocides, inhibitors, wettability modifiers, etc.).
- a chemical treatment(s) into the formation adjacent to the lateral borehole e.g. biocides, inhibitors, wettability modifiers, etc.
- the second end portion of the conduit is coupled to a rotational source, such as a fluid motor sized and configured to be run into the wellbore and capable of operating at the depth and conditions desired by the well operator.
- a rotational source such as a fluid motor sized and configured to be run into the wellbore and capable of operating at the depth and conditions desired by the well operator.
- a motor is Roper Pumps model 175R5640 procurable through Power Hydraulics (www.power-hydraulics.com), which motor is readily capable of producing in excess of 20 ft-lbs of torque under most operating conditions.
- the motor can be operatively coupled to a first end portion of the flexible spline member such that a torque generated by the motor is applied to the flexible spline member, thereby causing the flexible spline member to rotate.
- the motor may be configured such that the fluid pumping source may be in fluid communication with the first end portion of the flexible spline member by virtue of an upper cross-over member.
- the upper crossover member not only transmits torque but also allows for the concurrent transmission of fluid into the flexible spline member.
- the rotation source may be a surface-based rotational source, such as a power swivel.
- the rotational source connected to the downhole tool may be a DC motor.
- the downhole tool assembly of this disclosure includes a flexible spline member comprising a series of splined drive segments, or simply "drive segments", used to transmit torque around a radius.
- these drive segments are able to transfer torque without the need for or benefit of a shaft or fixed axis of rotation— something atypical to conventional gears and splines.
- the flexible spline member includes a first end portion and a second end portion wherein the first end portion can be coupled to a rotational source and the second end portion can be coupled to a lower cross-over member or cutting head assembly.
- the flexible spline member is capable of transitioning through and transmitting torque around an arc of 90 degree and having a radius of less than 12 inches, such as might be done on a wellbore having a 5.5 inch casing.
- the flexible spline member may allow torque to be transitioned around an arc with a radius of about 12 inches.
- the series of drive segments of the apparatus are sized and configured such that each drive segment engages at least one other drive segment such that torque is transmitted from drive segment to drive segment. While the drive segments can transition torque from one to another by meshing of mating drive teeth, technically the series of drive segments are not interlocked or interconnected to one another.
- the series of drive segments transmit torque through one or more projections (or teeth) on each side of a given drive segment and a respective mating socket(s) on an adjacent drive segment.
- each drive segment is configured with both a male projection or "tooth” and a female recess or “socket” on each side of the drive segment.
- each drive segment is configured with one or more tooth predominately or wholly on one side of the drive segment (i.e.
- the qualification that a given tooth and/or sockets is predominately on the one or the other sides stems from the fact that a given tooth or socket may cross over the base plane, such as may be possible if the two sides of the drive segment are suitably clocked or phased.
- both sides of a given drive segment have the same number of teeth and sockets.
- one side of a given drive segment might have 4 teeth and 4 sockets, while the other side of that same drive segment has 5 teeth and 5 sockets.
- the first end portion of the series of drive segments is operably connected to an upper cross-over member comprising a partial drive segment (e.g. a "one-sided” drive segment) that mates with an upper drive segment so as to allow the transmission of torque and fluid.
- the second end portion of the series of drive segments is operably connected to a lower cross-over member comprising a partial drive segment (e.g. a "one-sided” drive segment) that mates with an lower drive segment so as to allow the transmission of torque and fluid to the lower cross-over member and/or the cutting head assembly.
- the flexible spline member and series of drive segments are further sized and configured to transmit torque applied from the rotational source to the cutting head assembly such that the cutting head assembly is supplied with sufficient torque to cut the intended earthen formation.
- the flexible spline member may define at least one hollow cavity or inner passageway comprising at least one opening in each drive segment.
- a tubular member e.g. a hose
- the first end portion of the flexible spline member allows for external to internal porting whereby fluid may enter into the inside of the flexible spline member and optional tubular member so as to be directed to the cutting head assembly.
- the maximum diameter of the drive segment portion of the downhole tool is the same or nearly the same as the diameter cut by the drilling head. This can pre-empt the flexible spline member from appreciably deviating or helically buckling in the borehole being drilled. Normally, such a situation would create a scenario where the cuttings would have no return path to the wellbore and/or where the downhole tool were highly prone to becoming stuck.
- the series of drive segments may have one or more flats, grooves or flutes along their exterior edge. In embodiments, the one or more flats, grooves or flutes are positioned along the webbing that is situated between adjacent teeth of a given drive segment.
- a series of drive segments could have a barrel-shaped outer profile (wider at the center than at the ends) and flats along the webbing outer faces so as to provide a large cross-sectional area through which cutting may flow back to the wellbore.
- the difference between the maximum drilling head diameter and the maximum drive segment diameter may range to about 0.00" to about 0.025", while in other embodiments (typical to larger diameter drive segments) the difference may range to or exceed about 0.25".
- the distinct advantage of having the aforementioned diameters being identical or nearly identical is that by this method one can insure that a very straight borehole is drilled since the drilled borehole (whose size is dictated by the diameter of the cutting head) is not larger or appreciably larger than the drill-string itself. Again, a trailing drill-string cannot appreciable helically buckle in a borehole of essentially its same diameter. Furthermore, the drill head itself cannot meaningfully deviate from a straight-line trajectory on account of the fact that its attached, tightly constrained drill- string acts like a virtually rigid axis about which the drill-head rotates.
- the utilization of one or more unique drive segment designs cause each drive segment to center-up on its adjacent drive segment(s), when under torsional load.
- the greater the acting torsional load on a series of drive segments the more that series of drive segments try to line-up or self-center along a single, straight axis so as to drill a straight lateral borehole.
- weight applied to the top of the drill-string can be substantively and more effectively translated to the drilling head since the weight (i.e.
- Certain embodiments of the present invention may include an upper cross over member composed of an upper and lower threaded body housing a large interior space.
- the upper cross-over member can transmit both torque and fluid to the first end of the series of drive segments.
- the upper cross-over member directs fluid into a tubular member positioned inside of the series of drive segments.
- the upper cross-over member is coupled to a motor on its one end and on its other end to a partial, one-sided drive segment that is situated at a first end of the series of drive segments, so as to thereby allowing torque to be transmitted from the upper cross-over to the series of drive segments.
- the upper cross-over member directs fluid into a tubular member positioned inside of the inner passageway of the drive segments by way of a ported washer through which an optional tensioning line may pass.
- the upper cross-over member may allow for fluid to be diverted from upset tubing into the flexible spline member by virtue of a sealing mechanism positioned between the upper cross-over member and optional upset tubing or other circumscribing conduit.
- the upper cross-over member may function as part of a tensioning system capable of keeping the series of drive segments engaged with one another in certain circumstances, such as when not under torsional load and/or in a hard pull-back scenario.
- each drive segment may define one or more drive segment openings, which as a whole form at least one inner passageway.
- a tubular member such as flexible hose or tubing
- the tubular member are hose or braided hose, KEVLAR ® , convoluted tubing, interlocking hose, semi-rigid tubing, and the like.
- the tubular member is in fluid communication with the fluid pumping source and the cutting head assembly.
- the tubular member itself can be part of or it can circumscribe a separate, optional tensioning system, such as is discussed in a preferred embodiment, below.
- the tubular member within the flexible spline member can be fed, or transitioned, through a whipstock and into the earthen formation with the flexible spline member.
- seals positioned between the drive segments can be used to produce fluid communication between the opposite ends of the flexible spline member.
- fluid communication can be established between the first end of the flexible spline member end and the second end of the flexible spline member end, without usage of a hose or similar single continuous conduit.
- the sealing mechanism consists of elastomeric seals that are adhesively or mechanically bonded to adjacent drive segments.
- the flexible spline member comprises a lower cross-over member capable of mating the second end portion of the series of drive segments to the cutting head assembly by virtue of a "one-sided" drive segment.
- the other end of the lower cross-over member is then securely fastened to the cutting head assembly, such as by threading, welding or similar means.
- a tubular member contained in the inner passageway of the flexible spline member i.e. within the series of drive segments terminates at or in the lower cross-over member by such means as a hose crimp, another side of which can be securely fastened to the lower cross-over member, such as by threading.
- the lower cross-over member has one or more internal passageways allowing for fluid exiting the aforementioned tubular member to be passed to the cutting head assembly.
- the lower cross-over member may have a ported washer and associated lower rest through which an optional tensioning line may pass. Described more fully elsewhere herein, this lower rest may allow tension to be pulled on the optional tensioning line and hence on the series of drive segments, as a whole. Moreover, as the aforementioned lower washer may have multiple ports or grooves, fluid can freely flow through or around this washer; and hence to the cutting head. Thus, in embodiments, the lower cross-over member is designed to transmit torque, transmitting fluid and providing a steady rest for an optional tensioning line.
- the drive segments of the flexible spline member may be held in tension with one another by a distinct tensioning system, separate from the induced tension that may arise from the dynamic operation of the drive segments themselves.
- this optional tensioning system may be comprised of a tensioning line running from and affixed to the upper cross-over member on the one end and to the lower cross-over member (or the cutting head assembly) on the other end.
- the optional tensioning line has an upper end, which generally terminate in the upper cross-over member; and, a lower end, which generally terminates in the lower cross-over member.
- this tensioning line may be comprised of one or more hose(s) or cables(s), but it is preferable a single wire rope.
- the optional tensioning line is crimped or swedged on its lower end via a lower crimp, which is positioned so as to rest on the lower end of the lower washer (i.e. the washer housed in the lower cross-over member).
- This arrangement provides the tensioning system a lower "rest” against which tension can be pulled.
- the upper end of the tensioning line terminates in the upper cross-over member by means of an upper crimp (or swedge fitting) that is crimped to the tensioning line.
- the upper crimp can be brought to rest (or even pull) against one side of a washer (i.e.
- the bottom side of the upper washer can rest on a compression spring whose lower side in turn lands or is seat into the upper cross-over member.
- the upper crimp (which secures the tensioning line) itself terminates on its opposite end in a threaded extension, which is sized and then positioned so as to freely slip through an opening or slot running through the upper washer. A nut can then be tightened onto this threaded connection so as pull tension on the upper crimp and the attached tension line (the opposite end of which is secured in the lower cross-over member).
- tensioning means i.e. a tension line
- certain embodiments herein have their own form of dynamic tension which arises under rotation on account of the geometry of the mating teeth.
- the optional distinct tensioning system may be viewed as a sort back-up tensioning system.
- the cutting head assembly includes a cutting head, wherein the cutting head can be detachably attached to the cutting head assembly and further configured to be rotatable and to cut laterally through casing and/or cement and/or earthen formation.
- the cutting head assembly may be configured such that one or more orifices on or near the cutting head assembly are able to eject fluid near the cutting surface(s) or face(s). Fluid flow out of orifices on or near the cutting head assembly can be used to keep the cutting head cool and debris free so as to allow efficient cutting operations; residually this flow can also be used to facilitate the removal of cuttings from the borehole.
- the cutting head assembly may circumscribe a rotatable nozzle.
- the cutting face(s) can be formed from a hard material like carbide, poly-diamond crystals (PDC) or tool steel with specialized coatings.
- PDC poly-diamond crystals
- the lower cross-over member and the cutting head assembly are essentially indistinguishable assemblies— i.e. they are one and the same member.
- Each drive segment has an axis of rotation. Perpendicular to this axis of rotation is a base plane situated toward or at the center of the drive segment and dividing the drive segment into a first end and a second end.
- the first and second ends are symmetrical to one another, while in other embodiments, they are asymmetrical to one another.
- the clocking of the two sides may be identical to one another or out of phase with each other.
- Each drive segment also has an overall height and maximum diameter, wide combinations of which may be employed. In various embodiments, the maximum diameter of a drive segment may range from about 0.75" to about 3.5".
- a surface defines this passageway.
- this surface is a fixed distance (e.g. a "first radius") away from the axis of rotation, in which case the inner surface of the segment essentially forms a cylinder.
- the surface forms an inverted barrel shape, such as if a small arc with its apex located nearest an axis is rotated about that axis to form a surface; obviously, the contour of possible inner surfaces may vary widely
- each drive segment is comprised of one or more teeth on each side of the base plane and of one or more sockets on each side of the base plane.
- the teeth of the drive segments each have drive faces which, depending upon the direction of rotation of the flexible spline member, can be viewed as either driving or being driven.
- a driving face on one drive segment tooth forces - or drives - a driven face on a mating drive segment.
- a given drive segment essentially has one side about the base plane that is driven and another side about the base plane that is driving.
- a tooth drive face may be planar or curvilinear.
- a given tooth has not only a drive face, but also a leeward face or flank.
- the flank is the surface that is opposite the drive face of a given tooth; and, one may rightly consider the flank to be the "backside" of its respective tooth.
- top land On the top of a tooth is a top land, which surface may be planar or curvilinear. Similarly, in embodiments, at the bottom of a socket is a bottom land, which surface may also be planar or curvilinear.
- bottom land On the top of a tooth, at the bottom of a socket is a bottom land, which surface may also be planar or curvilinear.
- the top land of one tooth when a portion of the series of drive segments is rotated around a radius, the top land of one tooth lands into the bottom land of its mating socket. Both the top and the bottom land may be parallel, angled or skewed with respect to their base plane and/or each other. Discussed more fully, below, the shape of the top land and bottom land can be used to mitigate certain problems encountered by prior art employing segmented teeth.
- a webbing Situated between and connecting the adjacent teeth of a given drive segment is a webbing.
- This webbing has an inner and an outer surface and a first side and a second side.
- this webbing has an inner and outer surface that each co-terminates with part of the inner surface and outer surface, respectively, of that drive segment.
- a webbing's first side serves as the bottom land of a socket on a first side of the drive segment; while that webbing's second side serve as the bottom land of another socket on a second side of said segment.
- the webbing is readily identifiable as it sits at or near the base plane of a drive segment and is generally positioned between adjacent teeth.
- a top drive edge is the edge formed by a drive face and its adjoining top land; a bottom drive edge is the edge formed by a drive face and its adjoining bottom land; a top flank edge is the edge formed by a top land and its adjoining flank; a bottom flank edge is the edge formed by a bottom land and its adjoining flank.
- a drive face is perpendicular to its adjoining bottom land. In other embodiments, a drive face is acutely angled with respect to its adjoining bottom land. In embodiments, the angle between the drive face and its adjoining bottom land may range from about 88 degrees to about 70 degrees, while in other embodiments it may range from about 75 to about 60 degrees; while in still other embodiments it may be less than 60 degrees.
- a drive face is perpendicular to its base plane.
- a drive angle is acute—that is, the drive face is acutely angled to its base plane. That is, a drive face and its base plane form an angle of less than 90 degrees. In certain embodiments, this angle may range from about 88 to about 70 degrees, while in other embodiments it may range from about 75 to below about 55 degrees.
- a drive face is acutely angled both with respect to its base plane and its adjoining bottom land. In applicable prior art, there is no known instance of a drive face being acutely angled to its corresponding base plane.
- acutely angled drive faces have the noteworthy advantage of pulling adjoining drive segments together when in rotation; this can be a particularly helpful feature for keeping drive teeth splined together while transmitting torque around a radius.
- acutely angled drive teeth on mating drive segments can mitigate skipping or jacking apart of the drive segments - a problem which can have such catastrophic results as: chipped or broken teeth; a stalled and/or stuck drilling tool, and/or a tubular member (e.g. hose or other conduit) which becomes twisted up and/or otherwise fails.
- Determining an angle between a given drive face and its adjoining bottom land may be easily accomplished by intersecting the two surfaces with a plane perpendicular to the base plane.
- determining the angle between a drive face and its base plane may not be so obvious on account of the fact that the two surfaces may not directly intersect one another.
- a top land is acute with respect to its drive face.
- an angle formed by a top land and a drive face is from about 88 degrees to about 65 degrees, while in other embodiments, the angle is from about 65 degrees to about 50 degrees; while in still other embodiments, the angle may be less than about 40 degrees.
- a given top land and its respective base plane may be said to be acutely angled toward one another.
- the two surfaces are obviously not parallel to one another.
- that reference point is the given drive segment's axis of rotation.
- top land surface (or, for that matter, drive face, bottom land or flank surface) may be curvilinear, it may prove helpful here to discuss how one may determine the angle/orientation of such a surface of a drive segment to another surface or reference. In such instances, one may simply take the “mean” or “average” surface of that curvilinear surface and then project out this "representative" plane.
- a top land may form an acute angle with its base plane (and opening towards the axis of rotation) of between about 1 and about 10 degrees, while in still other embodiments, it may form an angle of about 8 to about 18 degrees, while in still other embodiments this angle may exceed 20 degrees.
- a multitude of acute angles defining the relation of a top land to its respective base plane are possible, and these are intended to be within the scope and intent of this disclosure.
- a bottom land of a drive segment is acutely angled with respect to its base plane.
- the axis of rotation as the point of reference by which to judge whether or not a "non- parallel" bottom land and its corresponding base plane are “acute” or “obtuse” with respect to the base plane.
- a bottom land and its base plane are judged to be acutely angled or acute with respect to one another when a plane perpendicular to said base plane intersects projections or extension of the bottom land and said base plane and thereby form an angle "opening towards" that drive segment's axis of rotation.
- a point on an inner edge of the bottom land will be a further distance from the base plane as a point on an outer edge of the bottom land if the points are located on a line extending through the axis of rotation.
- a bottom land may form an acute angle with its base plane of between about 2 and about 10 degrees, while in still other embodiments, it may form an angle of about 10 and about 20 degrees, while in still other embodiments this angle may exceed 20 degrees.
- a wide array of acute angles between a bottom land and its respective base plane are possible.
- a top land and a bottom land of a given drive segment may be parallel or angled with respect to each other.
- a webbing adjoining top land and bottom land may be parallel or angled to one another.
- projections of a webbing adjoining top land and bottom land may both form acute angles (with the base land) and open toward the axis of rotation.
- the measure of an acutely angled top land to its base plane is different than the measure of an acutely angled bottom land to that same base plane, even though both said top and bottom land are on the same drive segment.
- Embodiments with acutely angled top and/or bottom lands to their respective base plane allow better "nesting" of their respective series of drive segments when articulated and rotating. Again, while not known in prior art, embodiments with this configuration may allow improved contact between mating drive teeth faces and hence insure that said drive teeth remain reliably meshed when articulated and under torque.
- flank of a tooth is a sort of by-product of the sizing and geometry of its adjoining top land and bottom land. In a sense, it is the surface that arises out of joining a trailing edge of a top land (i.e. the non-drive face side of a top land) and a leeward edge of an adjacent bottom land (i.e. the side of the bottom land that is opposite the drive face).
- a flank may be shorter, equal to or taller than its conjoined drive face height (i.e. the face on the other side of the tooth).
- a drive segment of this disclosure wherein a flank height is taller than its conjoined drive face is likely to present splining challenges and inefficiencies, but in certain scenarios (and on account of other features) may allow adequate transmission of torque around a radius.
- the height of a flank is equal to or less than that of its associated drive tooth.
- the flank angle i.e. the angle a flank surface forms with its adjoining bottom land
- the flank angle is right, but in most preferred embodiments the angle is obtuse.
- flank angle allows for the easiest re- meshing of respective sets of teeth and mating sockets (on adjoining drive segments) when articulated and rotating around a radius.
- an angle that a flank and its adjoining bottom land form is between about 95 and about 120 degrees; while in other embodiments, it ranges from about 115 to about 135 degrees; while in still other embodiments it is between about 130 to about 155 degrees.
- the flank angle and the drive angle are complimentary angles; that is, in some embodiments, the drive face and flank surfaces are parallel to one another.
- lash The allowance of clearance, often referred to as lash, in between a socket and its mating tooth allows articulation of the series of drive segments around a radius.
- the lash between a tooth and socket is from about .005" to about .025", while in other embodiments it is from about .020" to about .045" and in yet other embodiments, it is well over 0.050".
- a further distinguishing characteristic of certain embodiments of this disclosure is a sort of "self-centering" geometry. That is, drive face geometry that causes the series of drive segments try to center-up along a single axis during operation, especially when rotating under high torsional resistance. In embodiments, this may be accomplished by defining helical surfaces on the drive face of the segments. Under rotation a drive segment having helical drive faces may not only be encouraged to rotate its adjoining segment (e.g. clockwise), but also to force itself into (or along) the same axis of rotation as that adjoining drive segment. As will perhaps be more evident in the figures, under rotation and in the presence of torque, a helical drive segment drive faces such that adjoining and mating drive faces pull into one another and toward a single, common center-line with each other.
- any or all the defining edges of the apparatus may have a radius, chamfer or other form of "edge break".
- a drive segment apparatus of this disclosure is one wherein one or more: drive face, top land or bottom land, is acutely angled with respect to its corresponding base plane and/or axis of rotation.
- a highly simplified and reliable method for providing tension along and fluid through a series of drive segments for short and ultra-short radius lateral drilling is provided. Variants of these designs, which rely upon their principles of design, are intended to be within the scope and intent of this disclosure.
- a whipstock is employed in at least one embodiment of the present invention.
- the whipstock refers to any downhole device capable of positioning the cutting head assembly toward the earthen formation desired for lateral cutting.
- the whipstock defines a guide channel sized and configured to receive and guide the cutting head assembly and at least a portion of the flexible spline member through the whipstock and toward the earthen formation of interest.
- the whipstock may guide the cutting head assembly into a substantially horizontal direction from a vertical wellbore such that the cutting head assembly is disposed approximately 90 degrees from the longitudinal axis of the wellbore.
- the whipstock may be disposed in the casing prior to the running of the downhole tool assembly.
- the whipstock may be set with a coil tubing unit, on the end of production tubing or it may be set by a wireline unit.
- the whipstock assembly may have one or more passageways extending from the guide path to below the whipstock to allow cuttings to freely fall toward the bottom of the wellbore.
- the bottom hole assembly may define one or more circulation passageways traversing through or around the whipstock, to allow for cleanout of the wellbore.
- the passageway(s) may serve as a circulation path for fluid that is circulated through the wellbore for the removal of cuttings, sand, paraffin and other materials that may have accumulated in the wellbore below the whipstock.
- any cutting in the wellbore maybe necessary for the proper operation of a tubing anchor.
- Pumping of fluid to circulate the wellbore through these opening(s) may be done initially, periodically or continuously. Cleaning out the wellbore and unloading the well may be accomplished by pumping fluid or gas at sufficiently high pressure and volumes through one or more of the circulation passageways.
- the method for cutting laterally from a wellbore is accomplished by feeding a portion of the flexible spline member and attached cutting head assembly through a whipstock pre-positioned downhole, while rotating said flexible spline member and ejecting fluid out the cutting head assembly.
- a coiled tubing and pumping equipment can be operatively connected to a downhole fluid motor in turn operatively connected to the upper end of the flexible spline member such that fluid pumped through the coiled tubing causes the mud motor to turn the flexible spline member and attached cutting head assembly, while at least some of said fluid is conveyed to and pumped through the flexible spline member and out the attached cutting head.
- the flexible spline member can be directed out of the wellbore through the pre- positioned whipstock, whereby the cutting head may cut a lateral borehole in the surrounding earthen formation.
- a tubular member disposed within the flexible spline member and in fluid communication with the fluid pumping source and the cutting head assembly may be used as a conduit to provide fluid to the cutting head while drilling.
- the flexible spline member and attached cutting head may be used to cut through the casing and/or cement, if present, and proceed to cut into the surrounding earthen formation.
- an e-line unit such as familiar to those in the industry, can be used to position and control the up-down travel of the downhole tool assembly.
- an electrically driven motor can be connected to the end of the e- line cable on the one end and to the flexible spline member and attached cutting head assembly on the other.
- This system can include one or more elastomeric sealing mechanisms positioned on or above the motor or upper cross-over member; the elastomeric mechanisms forming a relatively complete seal with the optional upset tubing.
- the sealing mechanism can be used to divert fluid flow through the upset tubing into the flexible spline member (such as via the upper cross-over member), where it may proceed to exit out the cutting head.
- a tubular member disposed within the flexible spline member and in fluid communication with the fluid pumping source and the cutting head assembly is used as a conduit to provide the fluid to the cutting head while drilling. Now rotating, the tool string can be lowered so as to traverse around the pre-positioned whipstock and thereby allow the cutting head to cut into the adjacent casing, cement and/or formation.
- a wireline or e-line unit can be utilized to control the vertical motion of the toolstring by controlling the motion of a downhole mud motor which is attached to the flexible spline member.
- a sealing mechanism with the optional upset tubing diverts the flow into the upper cross-over member which is attached to and impels the flexible spine member and attached cutting head to rotate.
- a tubular member disposed within the flexible spline member and in fluid communication with the fluid pumping source and the cutting head assembly is used as a conduit to provide fluid to the cutting head while drilling. Transitioned through the whipstock, the rotating flexible spine member and attached cutting head can cut into the adjacent casing, cement and/or formation.
- pumping equipment and jointed tubing positioned by drilling or work-over equipment, can be connected to a downhole fluid motor, which is in turn operably connected to the upper end of the flexible spline member.
- a downhole fluid motor which is in turn operably connected to the upper end of the flexible spline member.
- fluid pumped through the jointed tubing can cause the fluid motor to rotate, in-turn rotating the attached flexible spline member and cutting head assembly.
- a tubular member disposed within the flexible spline member and in fluid communication with the fluid pumping source and the cutting head assembly is used as a conduit to provide fluid to the cutting head while drilling.
- the flexible spline member and attached cutting head can be directed out of the wellbore by the jointed-tubing and pre-positioned whipstock so as to cut a lateral borehole in the surrounding earthen formation.
- the flexible spline member and attached cutting head may be used to through the casing and cement, if present, and proceed to cut into the adjacent casing, cement and/or formation.
- pumping equipment in communication with jointed tubing and drilling or work-over equipment is connected to a top-drive mechanism capable of rotating a jointed tubing string, which is in turn operably connected to the flexible spline member.
- a top-drive mechanism capable of rotating a jointed tubing string
- fluid pumped through the jointed tubing can cause the attached flexible spline member and " cutting head assembly to also rotate.
- the flexible spline member and attached cutting head can be directed out of the wellbore by lowering the jointed-tubing and transitioning the flexible spline member around the pre- positioned whipstock so as to cut a lateral borehole in the surrounding earthen formation.
- a tubular member disposed within the flexible spline member and in fluid communication with the fluid pumping source and the cutting head assembly is used as a conduit to provide fluid to the cutting head while drilling.
- the flexible spline member and attached cutting head may be used to through the casing and cement, if present, and proceed to cut into the adjacent casing, cement and/or formation.
- Figure 2 is a cross-sectional view of an embodiment of the present invention showing the flexible spline member (25) connected to a drive mechanism (53) by means of an upper cross-over member (86).
- the flexible spline member (25) has been guided through an incline (109) in the tubing (60) and into the guide channel (55) defined by a whipstock (54).
- the downhole tool assembly (63) includes a lower cross-over (85) connecting the flexible spline member (25) to a cutting head (50).
- the cutting head (50) is shown extending though a predefined opening (65) through the casing (62) and cement (61) and approaching the earthen formation (56).
- the whipstock (54) is positioned on tubing (60), optionally the whipstock (54) can be positioned on a packer (64) set within the cased wellbore (57).
- the cutting head (50) is shown extending though a portion of the casing (62) proximate the cement (51) and into the earthen formation (56).
- Figure 3 illustrates an openhole completed wellbore (80) containing an orienting device (54), illustrated as a whipstock, coupled to a section of tubing (60).
- the whipstock (54) has a channel (71) that can enable cuttings to exit out the whipstock (54) and fall to the bottom of the wellbore (91). sized and configured to guide at least a portion of the flexible spline member (25) of this disclosure to a position proximate the earthen formation (56).
- the wellbore (57) includes a layer of cement (61) disposed between the casing (62) and earthen formation (56).
- the cutting head (50) is connected to the flexible spline member (25) which is connected to a drive mechanism (53) by an upper cross-over member (86).
- a service vehicle (52) such as a coiled tubing unit is shown extending coiled tubing (66) into the tubing (60) and directing the cutting head (50), flexible spline member (25) and a drive mechanism (53) such as a mud motor to the whipstock (54).
- the drive mechanism (53) can convert fluid flow, such as flow through the coiled tubing (66) into rotational movement of the flexible spline member (25) and the cutting head (50).
- Figures 4a-4d illustrate examples of certain geometric construction lines of the disclosure.
- Fig 4a depicts a top view of a geometrical construction used to partially define what will become a drive face (13) intended for use in clockwise (CW) rotation.
- a given outer circle (98) will become the outer surface (18) of the drive segment (lc) and a concentric, smaller circle (97) will become the inner surface (17) of that drive segment (lc).
- the shared center point (O) of the two concentric circles (97 and 98) will ultimately lie along the axis of rotation (not shown) of this drive segment (lc).
- Fig 4b depicts a view from point (O) of Fig 4a, as if looking outward from the center (O) of the drive segment (lc), as if looking outwards towards the interior surface (17) of drive segment (lc).
- the base plane (2) becomes a line (shown here as a dotted line) subtending the bottom land (11) of the tooth (9).
- the drive face (13) is seen "underneath" the top drive edge (22).
- feature (Q) is really the line segment (Q)
- feature (P) is really the line segment (P) in Fig. 4a, above. That is, feature (Q) represents the drive face base edge (21) (or “bottom drive edge”) and feature (P) represents the top drive face edge or top drive edge (22) of drive segment (lc).
- the drive face (13) can be seen forming an acute angle (A) with its bottom land (12).
- Figs 4a and 4b one can see how a surface bounded by a top drive edge (22) and bottom drive edge (21) can be used to constructed a drive face (13). By repeating the procedure above at different angles on drive segment (lc), one can further construct other drive faces (not shown).
- Fig 4c depicts another geometric construction of a drive face (13) on a drive segment (lc) intended for clockwise rotation (CW). Defined similar to line segment P, above, line segment P2 in this figure will also serves as a top drive edge (22). In this case, however, the line segment Q2, namely, what will become the bottom drive edge (21) of our drive face (13) is defined as a line parallel but offset to line segment P2.
- line segment Q2 and hence the bottom drive edge (21) will also be closer to the base plane (2) than line segment P2, which defines the top drive edge (22).
- a drive face (13) can now be created by a surface spanning between line segments P2 and Q2.
- line segment P3 does not define the top drive edge (22); instead, the top drive edge (22) is constructed by a line segment (T) that deviates from line segment P3 by and acute angle (R2), opposite the direction of rotation (CW).
- the line segment (Q3), defining the face base edge (21) is clocked "still further along" than line segment (T), when the drive segment (lc) is under clockwise (CW) rotation.
- the eventual drive face (13) surface spanning between line segments (T) and (Q3) (which are on different planes than one another) is an example of a curvilinear drive face (13), which, in this case will also be helical.
- Figures 5a illustrates a top view of an embodiment of a drive segment of the flexible spline member (25).
- the drive segment includes an axis of rotation (3), an inner surface (6) that forms an inner passageway (8), an outer surface (7), a plurality of teeth (9) and a plurality of webbing sections (10).
- the overall profile of the drive segment is generally cylindrical in shape but can include flattened sides (31), which can enable greater fluid flow around the drive segment.
- a bottom land (11) associated with the webbing sections (10) and a top land (12) associated with the teeth (9) are shown, is a top drive edge (22).
- a flank (15) is shown as a portion of a tooth (9) that is connected to the webbing section (10) at a flank base edge (26).
- the teeth (9) connect with the webbing sections (10) at a flank base edge (26).
- An inner bottom land edge (11a) and outer bottom land edge (l ib) can be seen.
- the volume between adjacent teeth (9) define a socket (16).
- Figure 5b shows a side view of the drive segment (1).
- the base plane (2) of a drive segment (1) that is perpendicular to the axis of rotation (3) shown in Figure 5a.
- the outer surface (7) is shown having flattened side (31) portions.
- Drive faces (13) and flank (15) surfaces are shown in addition to the webbing (10).
- the angle (M) of the drive face (13) relative to the base plane (2) is shown as acute or less than 90 degrees.
- Figure 5c shows a side view of a series of drive segments (110) that are engaged together in a manner that can transmit torque and that can be articulated relative to each other.
- the axis of rotation (3), webbing sections (10), bottom land (11), top land (12), drive face (13) and flank (15) are shown. Additionally, one can see the flats (31) on the teeth (9) and webbing (10).
- Figure 5d shows a laid-open side view of a drive segment (1) with its base plane (2) and axis of rotation (3) shown.
- the teeth (9), webbing section (10) and flattened sides (31) are facing the viewer while the bottom land (11), top land (12) drive face (13), flank (15) face base edge (21) and leading edge (22) distinguish the profile.
- the angle (A) between the drive face (13) and the bottom land (11) is less than a 90 degree angle, while angle (C) between the flank (15) and the bottom land (11) is greater than a 90 degree angle.
- the flank (15) and drive face (13) have complimentary angles; that is, angle (A) and angle (C) sum to 180 degrees.
- the dimension (I) gives the distance of the bottom land (11) from the base plane (2), in this particular embodiment the bottom land (11) is parallel to the base plane (2).
- Figure 6 shows a laid-open side view of a drive segment (1) with its base plane (2) and axis of rotation (3) in the interior.
- Outer surface (7) of the teeth (9) and webbing sections (10) are facing the viewer while the bottom land (11), top land (12) drive face (13), flank (15) face base edge (21), leading edge (22) and flank base edge (26) distinguish the profile.
- the spaces between the teeth (9) can be referred to as female socket (16) into which teeth (9) of adjacent drive segments (1) can engage.
- the angle (A) between the drive face (13) and the bottom land (11) is less than a 90 degree angle
- angle (C) between the flank (15) and the bottom land (11) is greater than a 90 degree angle.
- the embodiment shown in Figure 6 illustrates a more aggressive profile in that the top land (12) has a greater slope relative to the base plane (2) than the embodiment shown in Figure 5d.
- flank (15) extends less from the base plane (2) than does the drive face (13), thereby imparting a slope to the top land (12) relative to the base plane (2), a slope that forms angle (K).
- the angle (J) is formed by the slope of the bottom land (11) relative to the base plane (2).
- Flats (31) can be seen on the webbing (10).
- Figure 7 shows a laid-open side view of an embodiment of a drive segment (1) with its base plane (2) and axis of rotation (3) shown.
- the teeth (9), webbing section (10) and outer surface (7) are facing the viewer while the bottom land (11), top land (12) drive face (13), flank (15) and leading edge (22) distinguish the profile.
- the bottom land (11) has an inside edge (11 A) with a dimension (HI) that is greater than an outside edge (1 IB) with a dimension (HO) so that the bottom land (11) has a slope towards the base plane (2) on moving from the inside (11 A) to the outside (1 IB).
- the top land (12) is parallel to the base plane (2).
- FIGs 8a illustrates a top view of an embodiment of a drive segment (1) of the flexible spline member (25).
- the drive segment (1) has a base plane (2) and axis of rotation (3), an inner passageway (8), an outer surface (7), a plurality of teeth (9), a plurality of webbing sections (10) and a plurality of sockets (16).
- the overall profile of the drive segment (1) is generally barrel shaped (33) but includes flattened sides (31), which can enable greater fluid flow around the drive segment (1).
- there is four flattened sides (31) and adjacent sides are perpendicular to each other as shown by the dashed lines forming a 90-degree angle (G).
- the flattened sides (31) are shown as associated with the webbing sections (10) while the more cylindrical sides (7) are associated with the teeth (9).
- a bottom land (11) associated with the webbing sections (10) and a top land (12) associated with the teeth (9) are shown as exposed portions of an end of the drive segment (1).
- a flank (15) is shown as a portion of a tooth (9) that is connected to the webbing section (10) at a flank base edge (26).
- Figure 8b shows a side view of a series of drive segments (110) that are articulated relative to each other and that are engage together in a manner that transmits torque around radius or curvature (3R) in the clock- wise (CW) direction.
- the drive segments (1), teeth (9), webbing sections (10), flats (31), bottom land (11), top land (12), drive face (13), flank (15), leading edge (22) and barrel shaped (33) outer profile (7) are shown.
- Angle (A) shows the angle formed between the drive face (13) and the bottom land (11).
- hose refers to elastomeric hose, single or multi-braided hose, sheathed hose, Kevlar® hose and comparable means of providing a fluid conduit.
- wire or “cable” refers to wire and cable whether single or multi-stranded, wire rope and similar means for securing or providing tension between two ends.
- fluid refers to liquids, gases or combinations thereof.
Abstract
Description
Claims
Priority Applications (3)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
AU2013313339A AU2013313339B2 (en) | 2012-09-10 | 2013-09-10 | Apparatus and method for lateral well drilling |
US14/426,819 US20150240573A1 (en) | 2012-09-10 | 2013-09-10 | Apparatus and Method for Lateral Well Drilling |
CA2884394A CA2884394C (en) | 2012-09-10 | 2013-09-10 | Apparatus and method for lateral well drilling |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
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US201261743678P | 2012-09-10 | 2012-09-10 | |
US61/743,678 | 2012-09-10 |
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WO2014039078A1 true WO2014039078A1 (en) | 2014-03-13 |
Family
ID=50237515
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Application Number | Title | Priority Date | Filing Date |
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PCT/US2013/000209 WO2014039078A1 (en) | 2012-09-10 | 2013-09-10 | Apparatus and method for lateral well drilling |
Country Status (4)
Country | Link |
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US (1) | US20150240573A1 (en) |
AU (1) | AU2013313339B2 (en) |
CA (1) | CA2884394C (en) |
WO (1) | WO2014039078A1 (en) |
Cited By (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2020204701A1 (en) * | 2019-04-04 | 2020-10-08 | Vmi Holland B.V. | Guiding device |
US11719052B2 (en) | 2018-02-15 | 2023-08-08 | Tier 1 Energy Solutions, Inc. | Flexible coupling for downhole drive string |
Families Citing this family (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US10724302B2 (en) * | 2014-06-17 | 2020-07-28 | Petrojet Canada Inc. | Hydraulic drilling systems and methods |
WO2017086943A1 (en) * | 2015-11-18 | 2017-05-26 | Halliburton Energy Services, Inc. | Segmented bend-limiter for slickline rope sockets and cable-heads |
US20180112468A1 (en) * | 2016-10-20 | 2018-04-26 | James Mark Savage | Radial Drilling in Horizontal Wells by Coiled-Tubing and Radial Drilling by E-Line and Slick-Line |
US11261695B2 (en) * | 2020-06-15 | 2022-03-01 | Saudi Arabian Oil Company | Systems and methods to remove and re-apply sealant on the annular side of casing |
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US5337839A (en) * | 1992-08-07 | 1994-08-16 | Amoco Corporation | Extending the lateral portion of a short-radius wellbore |
US6378629B1 (en) * | 2000-08-21 | 2002-04-30 | Saturn Machine & Welding Co., Inc. | Boring apparatus |
US6523624B1 (en) * | 2001-01-10 | 2003-02-25 | James E. Cousins | Sectional drive system |
US20100147045A1 (en) * | 2007-04-20 | 2010-06-17 | Jose Teixeira | Flexible drill shaft |
US20120067646A1 (en) * | 2010-09-07 | 2012-03-22 | Nitro Drill Technologies, Llc | Apparatus and Method for Lateral Well Drilling |
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US2515366A (en) * | 1948-05-04 | 1950-07-18 | John A Zublin | Heavy-duty flexible drill pipe |
US2717146A (en) * | 1953-04-09 | 1955-09-06 | John A Zublin | Heavy duty flexible drill pipe |
US6921397B2 (en) * | 2003-05-27 | 2005-07-26 | Cardia, Inc. | Flexible delivery device |
US8366559B2 (en) * | 2010-06-23 | 2013-02-05 | Lenkbar, Llc | Cannulated flexible drive shaft |
-
2013
- 2013-09-10 CA CA2884394A patent/CA2884394C/en active Active
- 2013-09-10 WO PCT/US2013/000209 patent/WO2014039078A1/en active Application Filing
- 2013-09-10 US US14/426,819 patent/US20150240573A1/en not_active Abandoned
- 2013-09-10 AU AU2013313339A patent/AU2013313339B2/en not_active Ceased
Patent Citations (5)
Publication number | Priority date | Publication date | Assignee | Title |
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US5337839A (en) * | 1992-08-07 | 1994-08-16 | Amoco Corporation | Extending the lateral portion of a short-radius wellbore |
US6378629B1 (en) * | 2000-08-21 | 2002-04-30 | Saturn Machine & Welding Co., Inc. | Boring apparatus |
US6523624B1 (en) * | 2001-01-10 | 2003-02-25 | James E. Cousins | Sectional drive system |
US20100147045A1 (en) * | 2007-04-20 | 2010-06-17 | Jose Teixeira | Flexible drill shaft |
US20120067646A1 (en) * | 2010-09-07 | 2012-03-22 | Nitro Drill Technologies, Llc | Apparatus and Method for Lateral Well Drilling |
Cited By (3)
Publication number | Priority date | Publication date | Assignee | Title |
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US11719052B2 (en) | 2018-02-15 | 2023-08-08 | Tier 1 Energy Solutions, Inc. | Flexible coupling for downhole drive string |
WO2020204701A1 (en) * | 2019-04-04 | 2020-10-08 | Vmi Holland B.V. | Guiding device |
US11607854B2 (en) | 2019-04-04 | 2023-03-21 | Vmi Holland B.V. | Guiding device |
Also Published As
Publication number | Publication date |
---|---|
AU2013313339B2 (en) | 2016-04-14 |
AU2013313339A1 (en) | 2015-03-12 |
US20150240573A1 (en) | 2015-08-27 |
CA2884394C (en) | 2018-05-01 |
CA2884394A1 (en) | 2014-03-13 |
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