Apparatus and Method for Lateral Well Drilling Utilizing a Nozzle Assembly with Gauge Ring and/or Centralizer

Abstract

An apparatus and method for cutting horizontally into an earthen formation including a nozzle assembly having a gauge ring mechanism and/or a centralizer mechanism that allows the nozzle assembly to remain along a consistent axis of travel during cutting. Embodiments can provide horizontal jetting into the earth's strata from both cased and uncased wells utilizing a rotating, swirling, pulsing or cavitating nozzles which can keep a relatively cuttings free downhole environment.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to U.S. provisional patent application No. 61/214,589 filed on Apr. 27, 2009.

FIELD

The present invention generally relates to a method and apparatus for jet drilling into the earth's strata surrounding a wellbore. More, specifically, the present invention relates to an apparatus and method to provide horizontal jet drilling into the earth's strata from both cased and uncased wells into the earth's strata.

BACKGROUND

A large number of wells have been drilled into earth's strata for the extraction of oil, gas, water, and other material there from. In many cases, such wells are found to be initially unproductive, or may decrease in productivity over time. In many of these cases 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 casing used for the transportation of the oil, gas, water or other material upwardly to the earth's surface. In other instances, the wellbore may be uncased at the zone of interest, commonly referred to as an “open hole” completion.

In an attempt to obtain production from unproductive wells and increase production in under producing wells, methods and devices for forming a hole in a well casing, if present, and forming a lateral borehole there from into the surrounding earth strata have been developed and are generally known by those skilled in the art. For example, a hole in cased wells can be produced by punching a hole in casing, abrasively cutting a hole in the casing, or milling out a section of casing. In open hole wells, the steps to form a hole in the casing are not required, but the methods for forming a lateral borehole into the surrounding strata are virtually identical to those used on cased well. Under both the cased and uncased scenarios, a type of whipstock is typically incorporated to direct the nozzle blaster out of the wellbore and into the surrounding formation.

The inability of the known tools and techniques to efficiently advance into formations can be due to the inability of non-rotating nozzles, or nozzles that do not produce swirling or pulsing type motions in the exiting fluid/gases, to cut a lateral borehole with a circular cross-sectional shape (360 degrees) in the formation in front of them, thereby not allowing the nozzle head to advance. Such problems may also be due to a rotating nozzle or nozzle heads that create a swirling, pulsing or cavitating pattern of fluids or gases that do not cut a large enough and/or consistent enough circular opening in the lateral borehole. In addition, under known techniques when hard portions of strata protruding into the lateral borehole are encountered, the lateral borehole may not be effectively jetted out without a significant amount of time. If the diameter of the lateral borehole is not large enough, subsequent fittings/flairs that connect the nozzle assembly to the hose or semi-rigid tubing may be unable to pass through the borehole. Also, if the diameter of the borehole cut in the formation is not large enough, the annulus space between the borehole edge and the outside diameter of the hose or semi-rigid tubing will be relatively small, thereby preventing cuttings from efficiently returning all the way to the vertical wellbore. This in turn can prevent the nozzle head assemble from being able to advance forward because the system fails to remove the cuttings.

Besides the aforementioned problems, there can be other shortcomings in the current techniques for lateral jet drilling, namely that the path of travel of the nozzle head can substantially deviate from being in a substantially horizontal or straight line. This can occur because the length of the nozzle bodies on lateral jet drilling assemblies are inherently short so that the nozzle body can make it around the tight radius of a whipstock. The short length, however, can cause the nozzle assembly to make a deviated or highly curved path rather than stay in a predominately straight line radiating out from the vertical wellbore.

To control weight on the downhole tools, certain known technologies proscribe utilizing a hose circumscribed with one or more springs. Such a method however is prone to suffer from one or more of the following shortcomings: the springs may provide an opportunity for cuttings or other debris to become trapped therein, bridging off in the lateral borehole, thereby preventing forward movement of the hose; the springs may create turbulent flow patterns allowing for the deposition of cuttings and hence bridging off of the hose; if cuttings become entrapped between one or more coils of the spring, it may cause the nozzle head to change its trajectory or otherwise jam the hose in the lateral borehole; with many formations being naturally fractured, the springs may become stuck in any such cracks or crevices; if the nozzle heads cuts away a softer zone of formation, leaving a ridge or edge, the coils of the spring may become stuck in these; and the coils of the spring may hang-up at the casing due to the occurrence of a incomplete cement-casing bond, potentially causing a catastrophic sticking of the hose in the formation.

In view of the above, it would be desirable to have a method and apparatus suitable for horizontal well jetting that can produce a lateral borehole of sufficient size. It would also be desirable to have a method and apparatus suitable for horizontal well jetting that addresses cuttings that accumulate in the wellbore. In addition, it would be desirable to have a horizontal jetting method and apparatus that can sufficiently advance into a formation in a substantially horizontal or straight line.

SUMMARY

The present invention is directed to an apparatus and method for penetrating into the earthen strata surrounding a wellbore.

In an embodiment, the present invention includes a nozzle assembly, a flexible tubing connected to the nozzle assembly, and a means to position the nozzle assembly adjacently through a wellbore into earthen strata. The nozzle assembly may be connected to one end of the flexible tubing and the opposing end of the flexible tubing may be coupled to a pumping unit capable of pumping gas, fluid, or a combination thereof through the flexible tubing. In an embodiment, the nozzle assembly includes a gauge ring mechanism positioned near the front of the nozzle assembly. The gauge ring mechanism includes a larger maximum diameter than any other portion of the nozzle body and is also larger than any fittings or connections that attach the nozzle assembly to the flexible tubing.

In an embodiment, the apparatus of the present invention also includes one or more centralizing mechanisms positioned on or near the nozzle assembly. In another embodiment, the apparatus of the present invention includes a means to position the nozzle assembly into earthen strata in a substantially horizontal direction and to optionally circulate through the positioning means. In a further embodiment, the apparatus may include a gauge ring and/or one or more centralizing mechanisms located on the nozzle head and/or flexible hose.

In an embodiment, the apparatus of the present invention for cutting horizontally into an earthen formation includes a hood mechanism to help ensure a suitable stand-off distance between a nozzle head of the nozzle head assembly and the formation, to protect the nozzle head, and to ensure that a minimum diameter hole is cut before the nozzle head is able to advance. In an embodiment, the hood mechanism can include a hood, a cap, or a gauge ring like device located on the forward end of the nozzle assembly.

In an embodiment, the present invention is directed towards a method for penetrating earth strata surrounding a wellbore including inserting a downhole tool containing a nozzle assembly having a rotatable nozzle head or a nozzle head that resulting in swirling, pulsing or cavitating jetting, a flexible tubing connected to the nozzle assembly, a means to position the nozzle assembly into earthen strata in a substantially horizontal direction, and wherein the nozzle assembly is connected to one end of the flexible tubing and the opposing end of the flexible tubing is coupled to a pumping unit capable of pumping gas, fluid, or a combination thereof through the flexible tubing to rotate the nozzle head into a wellbore. The method is directed to penetrating the earth strata in a substantially straight line such that the nozzle assembly remains along the same axis of travel as that which is initially cut by the nozzle. The method also includes guiding the downhole tool toward the earthen strata in a substantially horizontal direction so that the nozzle faces at least a portion of earth strata surrounding the wellbore and spraying gas, foam, fluid, or a combination thereof from the rotatable nozzle head into the earth strata and thereby cutting a lateral borehole into the earth strata.

In an embodiment, the present invention includes a method to create a suitable relatively cuttings free environment for the creation of a lateral borehole utilizing either a rotating nozzle head, pulsing nozzle head, cavitating nozzle head or one wherein a swirling or pulsing motion like flow pattern is created, or a non-rotating nozzle head wherein the nozzle assembly is rotated. In an embodiment, the method includes circulating gases, foam, fluids or a combination thereof through, around, and/or above a whipstock while the rotating nozzle head is in the lateral borehole or has been retracted into the whipstock.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a longitudinal cross sectional view of a downhole tool of the present invention having a nozzle assembly directed through a hole in a wellbore casing.

FIG. 2A is a longitudinal cross sectional view of a non-rotating nozzle assembly having a gauge ring apparatus and a centralizer apparatus.

FIG. 2B depicts frontal view of the non-rotating nozzle assembly of FIG. 2A.

FIG. 3A is a longitudinal cross sectional view of a rotating nozzle assembly having a gauge ring apparatus and a centralizer apparatus.

FIG. 3B depicts frontal view of the rotating nozzle assembly of FIG. 3A.

DETAILED DESCRIPTION

The apparatus of the present invention includes a downhole tool adapted for jet drilling into earthen strata surrounding both cased and uncased wellbores. The downhole tool of the present invention can include a flexible tube, such as a flexible hose or semi-rigid pipe, connected to pumping equipment at one end and connected to a nozzle assembly on the other end. In an embodiment, the nozzle assembly includes a nozzle head assembly. The nozzle head assembly can have a rotatable nozzle head, pulsing nozzle head, a cavitating nozzle head or one wherein a swirling or pulsing motion like flow pattern is created, or a non-rotating nozzle head wherein the nozzle assembly is rotatable. The pumping equipment is capable of pumping gas, fluid, or a combination thereof through the flexible tubing and out of the nozzle head assembly. In an embodiment, the nozzle assembly includes a stationary nozzle head assembly or a rotatable nozzle head assembly. In an embodiment, the rotatable nozzle head assembly is adapted to create a fluid bearing in the presence of the gases, fluids or combinations thereof flowing from the flexible tube and through the nozzle assembly. In an embodiment, the nozzle head assembly allows for fluid flow out of the frontal space between the rotatable shaft and the main body thereby creating a positive pressure near the nozzle head in order to facilitate debris-free rotation of said nozzle head.

In an embodiment, the nozzle head assembly contains a stationary nozzle head assembly. In an embodiment, the nozzle assembly may contain a stationary nozzle head, such as a button nozzle, and a means of securing the nozzle assembly to a hose or semi-rigid tubing. The nozzle assembly may allow fluid, gases or some combination thereof to flow through an interior passage way(s) into chamber located inside the stationary nozzle head. In an embodiment, the stationary nozzle head has at least one orifice wherein the fluid, gases or combinations thereof exit the nozzle assembly. In a further embodiment, the at least one orifice is arranged whereby the fluid, gases or combinations thereof exit the nozzle assembly in circular, or swirling, or pulsing motion. In an embodiment, the nozzle assembly may contain a chamfer ring in the interior of the nozzle assembly positioned forward of the nozzle head containing the at least one orifice. The chamfer ring may help to optimally direct the flow path of the fluid, gases or combination thereof upon exiting the at least one orifice.

In an embodiment, the nozzle assembly itself is rotatable. Rotation of the nozzle assembly can be advantageous in order to more readily allow it to transition through the radius of the whipstock and to move into and out of the earthen formation. A further advantage to a having a rotated nozzle assembly, regardless of its internal operation, is that if there is a failure on the part of an internal mechanism to create the otherwise desired rotation, pulsing or swirling, the rotated nozzle assembly may yet be capable of cutting the formation. That is, there is a redundant mechanism by which the formation can be cut. Rotation of the nozzle assembly may be accomplished by rotating a portion or all of the attached flexible tubing such as by a motor or by other means familiar to those in the art.

In an embodiment in which the nozzle assembly includes a rotatable nozzle head, the fluid, gases or combination thereof leaving the orifices on the rotatable nozzle head can generate the rotation of the nozzle head itself. In another embodiment, a shaft connected to the nozzle head is used to generate and transmit torque to the rotatable nozzle head. In yet another embodiment, in the presence of flowing gas, fluid or combination thereof, the interior shape of the main body of the nozzle assembly is used to create a swirling or pulsing pattern in the flow, thereby causing rotation of the rotatable shaft and thus the connected rotatable nozzle head. In an alternative embodiment, a rotatable or non-rotatable nozzle head assembly is connected to rotatable flexible tubing. In a further embodiment, a motor is connected to the flexible tubing, wherein the flexible tubing is rotatable. In an embodiment, the motor is driven by the flow of the fluid, gases or combination thereof thereby causing the rotatable flexible tubing to rotate wherein at least a portion of the fluid, gases or combination thereof used to drive the motor are transmitted inside the rotatable flexible tubing to the nozzle assembly in order to drive the rotatable nozzle head.

In an embodiment, the nozzle head assembly may contain a rotating nozzle head assembly and a means of securing the rotating nozzle head assembly to flexible tubing. In an embodiment, the combination of the nozzle head assembly with the flexible tubing allows for a fluid bearing to be created upon the pumping of a fluid, gas or combination thereof into the flexible tubing and subsequent nozzle head assembly. The nozzle head assembly may also allow fluid, gases or some combination thereof to flow through an interior passageway(s) into a space or chamber located inside the nozzle head. In an embodiment, the nozzle head has at least one orifice wherein the fluid, gases or combinations thereof exit the nozzle head assembly. In an aspect, the nozzle head assembly includes a nozzle body and a rotatable barrel body. In an alternative aspect, the nozzle body includes a rotatable barrel body and the rotatable barrel body includes the rotatable shaft such that the rotatable shaft is located inside the rotatable barrel body, wherein the rotatable barrel body contains at least one orifice at the rear of the barrel body and at least one orifice closer to the front of the barrel body such that a majority of the fluids, gases, or combinations thereof from the flexible tubing traverse an interior space of the barrel body creating a fluid bearing between the rotatable shaft and the barrel body and are delivered to the nozzle head. In another embodiment, the at least one orifice has a centerline that is pitched at an angle different than the angle of the axis of rotation of the nozzle head. In a further embodiment, the nozzle head has at least two orifices wherein at least one orifice is asymmetrically oriented. In an aspect, the nozzle head has at least one orifice skewed with respect to the axis of rotation of the nozzle head so as to provide a rotational impetus to the nozzle head.

In an embodiment, rotation of the nozzle head can be imparted from differential thrust created by the exiting gas or fluid acting on the nozzle head itself or on an attached rotatable shaft. In an embodiment, the nozzle head can include exit ports located on the front or back of the nozzle head itself, which upon flow of fluid, gas or combinations thereof, cause an imbalanced net thrust and hence impart rotation. In another embodiment, the thrust can be created by one or more ports on an attached shaft apparatus, wherein the one or more ports are sized, angled or located so as to cause an imbalanced net thrust, upon flow of fluid, gas or combinations thereof, on the rotatable shaft and attached nozzle head. In a further embodiment, thrust can be created by one or more exit orifice(s) located on the main body of the nozzle assembly, such that any gases or fluids exiting said orifice(s) cause an opposite rotational thrust on the shaft and attached nozzle head.

In an embodiment, the rotatable shaft of the nozzle head assembly contains one or more spirally-oriented internal or external fins, flutes, grooves or rifling, causing the shaft to act as if an impeller when subjected to flow of fluids, gases or combinations thereof. The flutes, grooves or rifling can be either on the inside or the outside of the rotatable shaft, or both. Furthermore, spirally-oriented flutes, grooves or rifling may also be situated about the inside of the main nozzle body in which all or part of a shaft can turn, in this case the flutes, grooves or rifling may impart a spiral flow pattern in the flowing gas, fluid or mixed combination, which can, in turn, transmit the impetus for rotation to the rotatable shaft and attached nozzle head.

In an embodiment, the nozzle assembly contains a hood mechanism. In an embodiment in which the nozzle assembly includes a rotating nozzle head, the hood mechanism can create a specific stand-off distance between the earthen formation being cut and the exit orifice(s) so as to allow for optimal jet drilling of the formation and to prevent the rotating nozzle from coming into to contact with the earthen formation, which could wear or damage the nozzle head, which could restrict nozzle head rotation or could cause the nozzle head to stop rotating. In an embodiment, the hood mechanism is designed so as to closely fit the nozzle head thereby acting as a choke point that minimizes the chances of cuttings or other debris from partially or totally plugging any gap between the hood and the rotating nozzle head, which could stop rotation of the nozzle head. In another embodiment, the hood mechanism is a perforated hood containing slots, groves or holes, which serve to direct cuttings around the nozzle assembly and to allow any cuttings that may accumulate between the hood and the nozzle head to freely exit. In a further embodiment, the slots, groves or holes traverse the hood from its interior and forward side to its exterior and rear side. In another embodiment, the nozzle hood can be installed as a cap around the nozzle head, such that the hood surrounds the circumference of the rotating nozzle. In an aspect, the nozzle head and the perforated hood could allow for the orifices on the nozzle head to cut the formation through slots in the perforated hood.

In an embodiment, the rear of the nozzle head may be tapered to a smaller diameter than the forward edge of the nozzle head. The tapered nozzle head can inhibit the rotating nozzle from being obstructed with debris in the event that any debris is able to get between the outside of the nozzle head and the interior of the hood, because a smaller space between the nozzle head and the hood at the forward part of the nozzle head results in a choke point whereby any material that gets past the choke point is in a relatively larger space and less likely to obstruct the nozzle head. In an embodiment, a gauge ring may be added to the front of the nozzle assembly. In an embodiment, an optional centralizer is added to the rear of the nozzle assembly. The gauge ring along with the optional centralizer can be added to ensure that a minimum diameter lateral borehole is cut.

In an embodiment, a gauge ring is positioned at the front of the nozzle assembly. In an embodiment, the gauge ring has a larger maximum diameter than any other portion of the nozzle body and is also larger than any fittings or connections that attach the nozzle assembly to the flexible tubing. By being of a larger diameter than all parts located behind it, the gauge-ring would ensure that a hole of at least a pre-defined size is cut in the formation so as to prevent the nozzle assembly and the flexible tubing, as well as any fittings or connections, from becoming stuck at any point in the laterally jetted borehole. In an embodiment, the gauge ring is integrated with the nozzle body. In another embodiment, the gauge ring is attached and secured to the nozzle body, such as by threading or crimping. In a further embodiment, the gauge ring is integral to the hood mechanism. In an embodiment, the gauge ring mechanism may contain a chamfer ring in the interior of the gauge ring mechanism positioned forward of the nozzle head containing the at least one orifice. The chamfer ring may help to optimally direct the flow path of the fluid, gases or combination thereof upon exiting the at least one orifice.

In an embodiment, the gauge ring mechanism may contain a chamfer connecting the forward end of the gauge ring with the outside surface of the gauge ring facing the lateral borehole wall. The chamfer can serve to partially guide the nozzle assembly along the path of the lateral borehole and/or around any proximal obstructions on the edges of the lateral borehole. In an embodiment, the gauge ring may extend longitudinally along the exterior of the nozzle body at or near full gauge in order to ensure that the cutting path of the nozzle head is along a virtually straight line and remains on the same or similar path as the main direction of the lateral borehole. In another embodiment, the gauge ring mechanism may have a chamfer connecting its back-facing edge to the outside surface of the gauge ring facing the lateral borehole wall so that when the flexible tubing and nozzle head are retracted from the lateral borehole, the gauge ring does not hang-up on a protrusion into the lateral borehole or at the hole in the wellbore casing. In another embodiment, the gauge ring may have one or more mechanisms to allow for the bypassing of fluid, gases, cuttings or a combination thereof from the front of the nozzle assembly towards the flexible tubing and, ultimately, toward the wellbore. This bypass can be accomplished through one or more holes, slots or grooves that allow said materials to move to the back and exterior of the gauge ring.

In an embodiment, the downhole tool of the present invention contains a centralizer mechanism. The centralizer mechanism can serve the purpose of keeping the rearward part of the nozzle assembly relatively centralized in the lateral borehole and therefore help ensure that the jet lateral path is along a relatively straight line. In an embodiment, the centralizer includes an extension of the frontal gauge ring that extends longitudinally along the exterior of the nozzle body. In another embodiment, the centralizer includes a second gauge ring located toward the anterior end of the nozzle assembly. In an additional embodiment, the centralizer includes multiple pins projecting outward on the outer surface and along the longitudinal axis of the nozzle assembly. The multiple pins may include at least 2 pins. The multiple pins can act as a centralizer by folding backwards as the nozzle head is moved into the formation. In an alternative embodiment, the centralizer includes at least 2 bow springs attached to the outer surface of the nozzle assembly. In a further embodiment, the centralizer includes multiple (at least 2) spring-loaded pins or pointers projecting radially outward along the nozzle head body. In an aspect, the nozzle assembly is centralized in the lateral borehole by the radial discharge of fluid, gases or a combination thereof toward the center or back of the nozzle head body.

The centralizer mechanism may be designed to allow for the passage of cuttings, fluids, gases or some combination thereof from the frontal nozzle head area toward the hose or semi-rigid tubing and back to the wellbore. In an embodiment, the centralizer mechanism contains slots, grooves or holes or a combination thereof that allow for the passage of cuttings, fluids, gases or some combination thereof from the frontal nozzle head area toward the hose or semi-rigid tubing and back to the wellbore. In another embodiment, cuttings, fluids, gases or some combination thereof can be removed from the frontal nozzle head area toward the hose or semi-rigid tubing and back to the wellbore by compression and/or retraction of the centralizing mechanism. In a further embodiment, cuttings, fluids, gases or some combination thereof can be removed from the frontal nozzle head area toward the hose or semi-rigid tubing and back to the wellbore by radial spacing of the centralizing mechanism(s).

In an embodiment, the nozzle assembly contains a forward positioned centralizing mechanism and one or more rear positioned centralizing mechanism(s). The longitudinal distance between any forward and rear positioned centralizing mechanism(s) can ensure that the nozzle assembly remains substantially along a single, primary axis of travel down the lateral borehole and can restrict the nozzle assembly from deviating from the primary axis of travel and creating another lateral borehole. In an embodiment, the longitudinal distance between any forward and rear positioned centralizing mechanism(s) is between 1 inch to 24 inches, optionally between 4 inches to 12 inches.

According to the embodiments of the present invention, the gauge ring and centralizer can be used with both non-rotating nozzles and rotating nozzles. In an embodiment, the nozzle assembly of the present invention can include both the gauge ring mechanism and the centralizing mechanism.

In an embodiment, the downhole tool of the present invention is connected to an assembly that can be used to lower the downhole tool inside a wellbore. In an embodiment the downhole tool is connected to a wireline assembly for placement and retrieval. In another embodiment, the downhole tool is connected to a section of tubing. In an aspect the tubing can include upset tubing or other non-upset tubing. In a further embodiment, the downhole tool is connected to a spool of tubing that can be lowered down a wellbore.

In an embodiment, the downhole tool of the present invention is contained in a tubing containment system prior to lowering of the downhole tool inside of a wellbore. In an embodiment, the tubing containment system includes one or more collapsible sleeves. In this embodiment, the collapsible sleeves are in an extended position and positioned atop a whipstock. Force can then be applied to the sleeves causing them to collapse. When the collapsible sleeves collapse, the flexible tubing within the collapsible sleeves is lowered into a guide channel in the whipstock.

In an embodiment, the tubing containment system includes one or more collapsible centralizers. In an embodiment, the one or more collapsible centralizers can be affixed to a given position on the flexible tubing and oriented radially around the flexible tubing. In an embodiment, this tubing containment system is capable of transitioning through the whipstock. This tubing containment system can keep the flexible tubing from collapsing over itself in the tubing located above the whipstock and can keep the flexible tubing and nozzle head assembly centralized in the lateral borehole. In an aspect, the one or more collapsible centralizers include bow-spring centralizers and/or pin centralizers. The bow-spring centralizers can be oriented lengthwise on the flexible tubing and the pin centralizers may extend radially from the flexible tubing.

In an embodiment, the tubing containment system includes a series of stackable sleeves containing the flexible tubing. In this embodiment, the stackable sleeves are in a stacked position and positioned atop a whipstock. Force is then applied to the sleeves causing them to “stack-out” above one another atop the whipstock. When the stackable sleeves stack-out above one another, the flexible tubing within the stackable sleeves is lowered into a guide channel in the whipstock. In a particular example, a 1-inch long sleeve is placed every foot along a 30 foot flexible tubing and when force is applied, the stackable sleeves would form a stack of stackable sleeves that is 30 inches long, resulting in the end of the flexible hose containing the nozzle assembly being 27.5 feet beyond the top of the whipstock.

In another embodiment, the flexible tubing containment system includes a lower section that is adaptable to the whipstock in order to form a seal with the whipstock. This seal may restrict the backflow of fluid and materials up the whipstock so as to seal out any cuttings washing back from the lateral borehole. This is desirable in order to keep cuttings from clogging the guide path, or channel, of the whipstock, which could inhibit the free travel of the flexible tubing.

In an embodiment, the downhole tool of the present invention includes a section of tubing situated on top of a whipstock. In order to prevent buckling of the flexible hose that is transitioned through the whipstock when weight is applied, the piece of tubing sitting atop the whipstock can be modified so as to have a smaller diameter than the standard 2⅜″ production tubing, typically used in the art. In an aspect, the inside diameter of this modified tubing is at least 1.1 times the outside diameter of the hose or semi-rigid tubing attached to the nozzle head assembly. In another aspect, the inside diameter of the modified tubing is from 1.25 to 2 times the outside diameter of the hose or semi-rigid tubing. In another aspect, the inside diameter of the modified tubing is from 2 to 3.5 times the outside diameter of the flexible hose or semi-rigid tubing.

In an alternative embodiment, a sheath style containment system through which the flexible hose can pass is positioned inside of the production tubing (or similar tubing) sitting atop the whipstock. This sheath containment system can be used to prevent the flexible hose that is transitioned through the whipstock from buckling in larger diameter tubing located above the whipstock when weight is applied. In an embodiment in which a containment sheath is used, the containment sheath can be held in place above the nozzle head assembly by a slip-type connection having a smaller inside diameter than at least one outside diameter of the nozzle head assembly, through which the flexible hose is able to advance.

In an embodiment the flexible tubing, hose or semi-rigid pipe connected to the nozzle head assembly can be fed, or transitioned, through a whipstock and into the earthen formation for the jet drilling of a lateral borehole at high pressures. In an embodiment, these pressures are greater than 2,000 psi. In another embodiment, these pressures are from 3,000 to 20,000 psi. In an alternative embodiment, these pressures are from 5,000 to 15,000 psi. In a further embodiment, the jet drilling is performed under pressures of from 7,000 psi to 10,000 psi. In an embodiment, the operating flow of the gas, fluid or combinations thereof ranges from 6 to 12 gallons per minute (gpm). In another embodiment, the operating flow ranges from 10 to 20 gpm. In a further embodiment, the operating flow ranges from 15 to 35 gpm. In an embodiment, the whipstock includes one or more passageways that allow cuttings, sand, paraffins, scale and/or materials to fall below the whipstock and to be circulated out by the flow of fluids, gas or a combination thereof

In an embodiment, the flexible tubing is selected from the group of a multi-braid hose, a single braid hose, a fabric-circumscribed hose (e.g. Kevlar®), and semi-rigid tubing. In another embodiment, the flexible tubing includes a multi-braid hose. In a further embodiment, the flexible tubing does not contain a spring or any other stiffening mechanism permanently attached to and on the outside of the flexible tubing. In an alternative embodiment, the flexible tubing does not contain a spring or any other stiffening mechanism on its outer surface when the nozzle assembly is deployed in a cutting position, such as after the nozzle assembly has transitioned through the whipstock.

The present invention is also directed to a method of jetting earthen strata surrounding both cased and uncased wells. In an embodiment, the method can include inserting a flexible tubing having a nozzle assembly at one end into tubing in a wellbore. In an embodiment, the nozzle assembly contains a stationary nozzle head. In another embodiment, the nozzle assembly contains a rotatable nozzle head with at least one orifice on one end of the rotatable nozzle head. In an embodiment, the tubing is positioned on top of a whipstock having a guide path. In an embodiment the method includes: inserting the flexible tubing along the guide path of the whipstock until the nozzle head protrudes from the whipstock; injecting a gas and/or fluid at high pressure, such as between 4,000 and 20,000 psi into the flexible tubing, wherein the gas and/or liquid exits at least one orifice in the nozzle head; jetting a lateral borehole in the earth's strata with the gas and/or fluid exiting the nozzle head. In an embodiment, the gas and/or liquid exits the at least one orifice in a rotatable nozzle head and creates a fluid bearing between the rotatable nozzle head and the nozzle assembly.

In an embodiment, the downhole hose containment apparatus and methods for cleaning a wellbore disclosed herein may used in conjunction with certain non-rotating nozzle assemblies that rotate, pulse, create cavitation or create a swirling motion in the fluid or gas spray pattern. Pulsing nozzle head assemblies typically work by mechanical flow-blocking or mechanical flow-adjustments or produce pulsation by self-excitation of the jet flow. For example, the pulsing motion may be accomplished by having one or more orifices that are cyclically opened and closed or it may be created by one or more fast-acting valves or by a swirling disk that alternately opens and closes flow to an orifice. Cavitating nozzles typically have a series of specially designed chambers that facilitate the creation of cavitation bubbles. Nozzles that create swirling motions in the spray pattern typically do so by one or more fins, grooves, slots, perforated disks or orifices asymmetrically aligned to the longitudinal axis of the nozzle head assembly and are known by those familiar in the art.

FIG. 1 is a view of a wellbore 1 containing a downhole tool 2 of the present invention having a nozzle assembly 4 connected to a flexible tubing 6 as it transitions through the radius 8 of the guide channel 10 of a whipstock 12. The whipstock is shown connected to an optional stabilizing/centralizing packer 13. The guide channel may be used for directing the nozzle assembly from the whipstock to the adjacent wellbore casing. The nozzle assembly is depicted containing a forward gauge ring 16 with a centralizing mechanism 18.

FIG. 2A is a view of a non-rotating, or stationary, nozzle assembly 30. The main nozzle body 32 can be seen with an anterior section or fitting 34 that serves as a means to secure the main body 32 to the flexible tubing 6. The nozzle assembly 30 has a forward-located nozzle section 36 with one or more exit orifices 38, which are connected to an interior hollow flow path 40 (see arrows). The nozzle assembly 30 includes a gauge ring 42 that has a maximum diameter that is larger than that of the main nozzle body 32, connection fitting 10, flexible tubing 6 and any other non-compressible portion of the tool string or additional tool(s) that might be moved out the lateral borehole 14. An optional centralizing mechanism 46 that is compressible may in some cases have a diameter larger than the gauge ring 42, such as a centralizing mechanism 46 having bow springs that can expand to a diameter larger than the gauge ring 42, but can compress to a diameter that is less than the gauge ring 42. The gauge ring 42 may be integral to the main body 32 or may be a separate, attached piece. Additionally, the gauge ring 42 may have one or more holes or grooves 44 through its front section towards its rear, which allow for cuttings, fluid, gases or combination thereof to pass backwards (as shown by arrows) towards the wellbore (not shown). Toward the middle or anterior of the nozzle assembly 30 is an optional centralizing mechanism(s) 46, which help ensure that the nozzle assembly 30 remains pointed along the same axis 15 as that of the lateral borehole 14. Also, a rearward centralizing mechanism 46 is shown as flexible pins secured to the connection fitting 34.

FIG. 2B is a frontal view of the apparatus with exit orifice 38 and gauge ring 42 showing holes 44 through the forward part of the gauge ring 42 that allow for fluid, gas, cuttings or a combination thereof to flow (see arrows) to the outside and around the perimeter of the nozzle head body (not visible) and, ultimately, toward the wellbore (not shown).

FIG. 3A is a view of a rotating nozzle assembly 50 with gauge ring 60 and with interior passageway 54 for the transport of gases, fluids or a combination thereof to a rotating nozzle head 56 having exit orifice(s) 58a,b,c. The gauge ring 60 is shown here with an internal, frontal chamfer 61 that is designed to avoid obstructing the flow from the widest forward-pointed orifice 58b (see arrow). The gauge ring 60 has a radius or chamfer 62 on its external, frontal edge to help guide the nozzle assembly 50 down the lateral borehole 14. Additionally, one or more slots or grooves 64 are depicted that traverse to the outer and back edge of the gauge ring 60 and allow gas, fluids, cuttings or a combination thereof to flow (see arrows) away from the front of the nozzle assembly 50 towards the wellbore (not shown). A chamfer or radius 66 is located on the back of the gauge ring 60 that allows the nozzle assembly 50 to be easily retracted from the lateral borehole 14. The gauge ring 60 is shown with a longitudinal extension 68 used to help maintain the nozzle assembly 50 to point down the axis 15 of the lateral borehole 14. An optional centralizing mechanism, shown here as bow springs 70, can be used to further centralize and keep the nozzle assembly 50 traveling along the axis 15 of the lateral borehole 14.

FIG. 3B is a frontal view of an alternate gauge ring 60 embodiment wherein the passageway for fluid, gas, cuttings or a combination thereof, is through one or more longitudinal slots or grooves 64 (see arrows) that extend from the frontal edge of the gauge ring 60 toward its back edge (not shown). These slots or grooves 64 allow for the flow of fluid, gases, cuttings or a combination thereof to flow past toward the wellbore (not shown). Also visible in this view is a nozzle head 56, which in this case is a rotating head (note arrow), with one or more exit orifices 58a,b,c.

As used herein, the term “asymmetrically oriented” refers to the orientation, pitch, or angle of the centerline of an orifice wherein the centerline extending away from the front of the orifice never crosses the axis of rotation of the rotating nozzle head.

As used herein, the term “chamfer” refers to a beveled edge connecting two surfaces. More specifically, the term “chamfer” refers to a beveled edge connecting the front edge of the gauge ring mechanism to the outside surface of the gauge ring mechanism facing the lateral borehole wall.

As used herein, the term “earth's strata,” also referred to as “earthen strata” or “strata,” refers to the subterranean formation also referred to as earthen formation.

As used herein, the term “flexible tubing” refers to any hose, semi-rigid pipe, or hollow tubing that is able to flex or bend. The terms “flexible tubing,” “hose,” and “semi-rigid pipe” can be used interchangeably.

As used herein, the term “fluid bearing” refers to a bearing which at least partially supports the load of the bearing on a layer of liquid or gas.

As used herein, the term “substantially horizontal direction” refers to a direction away from the vertical wall of the wellbore of from 1 degree to 179 degrees.

As used herein, the term “lateral,” or “lateral borehole,” refers to a borehole that is drilled or cut from inside the wellbore and/or casing to a point away from the wellbore and/or casing in a substantially horizontal direction.

As used herein, the term “lateral jet drilling” refers to the drilling of a lateral borehole by means of pressurized gas or liquid or combinations thereof

Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.

As used herein, the term “stationary nozzle assembly” refers to a nozzle assembly having a stationary nozzle head.

As used herein, the term “stationary nozzle head” refers to a non-rotating nozzle head.

As used herein, the term “substantially horizontal direction” refers to a direction away from the vertical wall of the wellbore of from 1 degree to 179 degrees.

As used herein the term “whipstock” is used to include any downhole device that is able to position the rotating nozzle head assembly toward the earthen formation.

Depending on the context, all references herein to the “invention” may in some cases refer to certain specific embodiments only. In other cases it may refer to subject matter recited in one or more, but not necessarily all, of the claims. While the foregoing is directed to embodiments, versions and examples of the present invention, which are included to enable a person of ordinary skill in the art to make and use the inventions when the information in this patent is combined with available information and technology, the inventions are not limited to only these particular embodiments, versions and examples. Other and further embodiments, versions and examples of the invention may be devised without departing from the basic scope thereof and the scope thereof is determined by the claims that follow.

Claims

1. An apparatus for cutting into an earthen formation, comprising:

a nozzle assembly;

a flexible tubing connected to the nozzle assembly;

a means to position the nozzle assembly into earthen strata in a substantially horizontal direction;

wherein the nozzle assembly is connected to one end of the flexible tubing and the opposing end of the flexible tubing is coupled to a pumping unit capable of pumping gas, fluid, or a combination thereof through the flexible tubing; and

wherein the nozzle assembly comprises a gauge ring mechanism having a forward exterior surface, a side exterior surface, and a back-facing edge; and

wherein the gauge ring mechanism comprises a larger maximum diameter than any non-compressible portion of the nozzle body and is also larger than any non-compressible fittings or connections that attach the nozzle assembly to the flexible tubing.

2. The apparatus of claim 1, wherein the nozzle assembly comprises a nozzle body connected to the flexible tubing and a nozzle head connected to a hollow shaft, wherein the hollow shaft is positioned inside the nozzle body resulting in the flexible tubing being in open fluid communication with the nozzle head.

3. The apparatus of claim 2, wherein the nozzle head comprises at least one orifice.

4. The apparatus of claim 3, wherein the at least one orifice is arranged asymmetrically on the nozzle head.

5. The apparatus of claim 3, wherein the nozzle head comprises at least two orifices that are arranged asymmetrically and at least one orifice has a different size than another orifice on the nozzle head.

6. The apparatus of claim 4, wherein the nozzle head is self rotatable under operating conditions due to an asymmetrical thrust caused by at least one of the group consisting of the arrangement, the size, and the angle and combinations thereof of the at least one orifice when fluids, gases, or combinations thereof exit the at least one orifice.

7. The apparatus of claim 2, wherein the nozzle head comprises a hood that surrounds the circumference of the nozzle head.

8. The apparatus of claim 7, wherein at least a portion of the hood is perforated.

9. The apparatus of claim 1, wherein the gauge ring mechanism further comprises a chamfer connecting the forward exterior surface of the gauge ring with the side exterior surface of the gauge ring.

10. The apparatus of claim 1, wherein the gauge ring mechanism extends longitudinally along the exterior of the nozzle body at or near full gauge.

11. The apparatus of claim 1, wherein the gauge ring mechanism further comprises a chamfer connecting its back-facing edge to the side exterior surface of the gauge ring.

12. The apparatus of claim 1, wherein the nozzle assembly comprises a centralizer mechanism.

13. The apparatus of claim 12, wherein the centralizer mechanism is adapted to allow for the passage of cuttings, fluids, gases or some combination thereof from the frontal nozzle head area toward the hose or semi-rigid tubing and back to the wellbore.

14. The apparatus of claim 12, wherein the centralizer mechanism comprises slots, grooves or holes or a combination thereof

15. An apparatus for cutting into an earthen formation, comprising:

a nozzle assembly;

a flexible tubing connected to the nozzle assembly;

a means to position the nozzle assembly into earthen strata in a substantially horizontal direction;

wherein the nozzle assembly is connected to one end of the flexible tubing and the opposing end of the flexible tubing is coupled to a pumping unit capable of pumping gas, fluid, or a combination thereof through the flexible tubing; and

wherein the nozzle assembly further comprises a centralizer mechanism.

16. The apparatus of claim 15, wherein the centralizer comprises at least 2 pins projecting outward on the outer surface and along the longitudinal axis of the nozzle assembly.

17. The apparatus of claim 15, wherein the nozzle assembly comprises a gauge ring mechanism positioned near the front of the nozzle assembly.

18. The apparatus of claim 17, wherein the centralizer mechanism comprises a second gauge ring located toward the anterior end of the nozzle assembly.

19. A method for penetrating earth strata surrounding a wellbore comprising:

inserting a downhole tool comprising: a nozzle assembly having a nozzle head, a gauge ring mechanism; a flexible tubing connected to the nozzle assembly; a means to position the nozzle assembly into earthen strata in a substantially horizontal direction; and wherein the nozzle assembly is connected to one end of the flexible tubing and the opposing end of the flexible tubing is coupled to a pumping unit capable of pumping gas, fluid, or a combination thereof through the flexible tubing to exit the nozzle head and jet into the earthen strata;

guiding the downhole tool toward the earthen strata in a substantially horizontal direction so that the nozzle faces at least a portion of earth strata surrounding the wellbore;

ejecting gas, foam, fluid, or a combination thereof from the rotatable nozzle head into the earth strata; and

jetting a lateral borehole into the earth strata;

wherein during the jetting the nozzle assembly substantially remains along the same axis of travel as that which is initially cut by the nozzle.

20. The method of claim 19, wherein the method further comprises the step of removing cuttings from the wellbore.

20. The method of claim 19, wherein the downhole tool further comprises a centralizer mechanism.

21. The method of claim 19, further comprising a second tubing string other than the flexible tubing, the second tubing capable of circulating gases, foams, fluids, or a combination thereof within a wellbore to remove cuttings and/or debris from the wellbore, wherein said circulation can be performed during one or more of: prior to jetting the lateral borehole; periodically during jetting the lateral borehole;

continuously while creating the lateral borehole; or subsequent to jetting the lateral borehole into the earth strata.

22. A method for penetrating earth strata surrounding a wellbore comprising:

inserting a downhole tool comprising: a nozzle assembly having a nozzle head, a centralizer mechanism; a flexible tubing connected to the nozzle assembly; a means to position the nozzle assembly into earthen strata in a substantially horizontal direction; and wherein the nozzle assembly is connected to one end of the flexible tubing and the opposing end of the flexible tubing is coupled to a pumping unit capable of pumping gas, fluid, or a combination thereof through the flexible tubing to exit the nozzle head and jet into the earthen strata;

guiding the downhole tool toward the earthen strata in a substantially horizontal direction so that the nozzle faces at least a portion of earth strata surrounding the wellbore;

ejecting gas, fluid, or a combination thereof from the rotatable nozzle head into the earth strata; and

jetting a lateral borehole into the earth strata;

wherein during the jetting the nozzle assembly substantially remains along the same axis of travel as that which is initially cut by the nozzle.

23. The method of claim 22, wherein the downhole tool further comprises a gauge ring mechanism.

24. The method of claim 22, further comprising a second tubing string other than the flexible tubing, the second tubing capable of circulating gases, foams, fluids, or a combination thereof within a wellbore to remove cuttings and/or debris from the wellbore, wherein said circulation can be performed during one or more of: prior to jetting the lateral borehole; periodically during jetting the lateral borehole; continuously while creating the lateral borehole; or subsequent to jetting the lateral borehole into the earth strata.