WO2012034001A1

WO2012034001A1 - A method for finding and re-entering a lateral bore in a multi-lateral well

Info

Publication number: WO2012034001A1
Application number: PCT/US2011/050970
Authority: WO
Inventors: Michael Dean Rossing
Original assignee: Weatherford/Lamb, Inc.
Priority date: 2010-09-09
Filing date: 2011-09-09
Publication date: 2012-03-15
Also published as: US20120061141A1; GB2497054A; NO20130368A1; CA2811058A1; GB201305064D0

Abstract

A system and method of locating and entering a lateral wellbore (25,35) that extends from a primary wellbore (5) are provided. The system may include a coiled tubing (10) jointed tubular (10) continuous rod (10) and/or wireline conveyance menber (10), a connection assembly (20), an orientation assembly (32), a measurement assembly (40), a deflection assembly (50), a sub assembly (60), and a guide assembly (74). The method may include locating a tool string adjacent to a lateral wellbore that extends from a primary wellbore, measuring an inclination and azimuth of the tool string, comparing the measured data to existing survey data of at least one of the primary and lateral wellbores, orinting the tool string in the direction of the lateral wellbore, entering the lateral wellbore, and verifying that the tool string has entered the lateral wellbore.

Description

A METHOD FOR FINDING AND RE-ENTERING A LATERAL BORE IN A MULTILATERAL WELL

BACKGROUND OF THE INVENTION

Field of the Invention

[0001] Embodiments of the invention relate to systems and methods for indentifying and entering lateral wellbores that extend from a primary wellbore. Embodiments of the invention further relate to locating a lateral wellbore, in either a cased or open-hoied section of a primary wellbore, using a conveyance member, including but not limited to coiled tubing, jointed tubulars, continuous rod, and/or wireline, and a tool string that allows an operator to orient and direct the tool string into the lateral wellbore. Embodiments of the invention further relate to systems and methods for measuring downhole characteristics, such as wellbore depth, direction, and inclination, transmitting a signal corresponding to the measured downhole characteristics to the surface of the wellbore via electrical telemetry, mud pulse telemetry, electromagnetic telemetry, etc., comparing the measured downhole characteristics to existing survey data, and verifying a location of a lateral wellbore based upon the compared data.

Description of the Related Art

[0002] The purpose of drilling multiple lateral wellbores from a single primary wellbore is to increase access to one or more reservoirs without incurring the cost of surface casing, surface site preparation, and other expenses associated with drilling multiple primary wells originating at the earth's surface. Lateral wellbores are drilled by re-entering the primary wellbore and performing a sidetrack operation. In cases where wellhead space is limited, such as in offshore applications, the advantages of multiple lateral wellbores are compounded further.

[0003] The downside to drilling multiple lateral wellbores, however, is that subsequent workover operations requiring re-entry into a specific lateral wellbore of the multi-lateral well can be difficult. There is no control, absent special methods and apparatus, over which lateral wellbore a work string will enter upon being lowered into the multi-lateral well. The general problem becomes one of directing the work string into the desired branch.

[0004] There are a few known methods used to re-enter a lateral wellbore, however, these methods are extremely time consuming and at least partly rely on a trial and error process. One known method is described as the "Poke and Hope" method. This method locates a work string near a lateral wellbore junction and uses a knuckle joint and an orienter in an effort to manipulate an end of a work string into the lateral wellbore. The work string is simply lowered to the bottom of the lateral wellbore, and the recorded maximum depth is compared to known well depth data to determine which lateral wellbore the work string has entered. The work string may then be returned to the depth of the lateral wellbore junction, manipulated and lowered again, it being assumed that the work string has entered into another lateral wellbore. The work string is again lowered to the bottom of the second lateral wellbore; the recorded maximum depth is again compared to known well depth data to determine which lateral wellbore the work string has subsequently entered. The "Poke and Hope" method can be time consuming if there are several lateral wellbores in close proximity, since the method relies on the comparison of the "tagged" or "bottomed-out" data of each wellbore to ultimately identify a specific wellbore. A big drawback of the method includes obstructions in one or more of the lateral wellbores that can falsely indicate that the work string has bottomed out, thereby providing a recorded depth that does not match any of the known well data. Even worse, the recorded depth may match the depth of a different lateral wellbore, thereby leading to an incorrect assumption that the work string is in a specific lateral wellbore when it is not. [0005] Another known method is described as the "Enhanced Poke and Hope" method. This method uses a fluid activated assembly connected to a work string that provides a signal, such as a pressure decrease, when the work string is reciprocated through an area of a lateral wellbore junction and "pokes" into the lateral wellbore. The location of the lateral wellbore junction is used as a reference point and the work string is then lowered, again with the assumption that the work string has entered the lateral wellbore. The recorded depth at the bottom is then compared to known well depth data as described above. This method also suffers from the same drawbacks described above.

[0006] Therefore, there is a need for an improved system and method for identifying and entering a lateral wellbore in a multi-lateral well. SUMMARY OF THE INVENTION

[0007] In one embodiment, a method of locating and entering a lateral wellbore that extends from a primary wellbore may comprise running a tool string into the primary wellbore to a location adjacent to a junction between the primary and lateral wellbores using existing survey data of at least one of the primary and lateral wellbores. The method may further comprise deflecting the tool string at an angle relative to a longitudinal axis of the tool string; measuring an inclination and an azimuth of the tool string; and comparing the measured inclination and azimuth to existing survey data of the lateral wellbore. The method may further comprise running the tool string past the location adjacent to the junction and in a direction of the lateral wellbore based on the comparison of the measured inclination and azimuth to the existing survey data of the lateral wellbore; and measuring an inclination and an azimuth of the tool string after running it past the location adjacent to the junction and comparing the measured inclination and azimuth to existing survey data of the lateral wellbore to verify that the tool string has entered the lateral wellbore. [0008] In one embodiment, a method of locating and entering a lateral wellbore that extends from a primary wellbore may comprise locating a tool string adjacent to a junction between the primary and lateral wellbores. The method may further comprise measuring a first downhole characteristic at the junction using a measurement assembly of the tool string; comparing the measured first downhole characteristic to existing survey data of the lateral wellbore; and positioning the tool string in a direction of the lateral wellbore based on the comparison of the measured first downhole characteristic and the existing survey data of the lateral wellbore. The method may further comprise moving the tool string in the direction of the lateral wellbore; measuring a second downhole characteristic after the tool string has been moved in the direction of the lateral wellbore; and comparing the measured second downhole characteristic to existing survey data of the lateral wellbore to verify that the tool string has entered the lateral wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

[0009] So that the manner in which the above recited features of the invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

[0010] Figures 1-5 illustrate a method of identifying and entering a lateral wellbore from a primary wellbore according to one embodiment.

DETAILED DESCRIPTION

[0011] Figure 1 illustrates a conveyance member 10 connected to a tool string 100 that is located in a primary wellbore 5. In one embodiment, the conveyance member 10 may include a coiled tubing string that is provided from a spoolable mechanism 13 at the surface of the primary wellbore 5. The spoolable mechanism 13 may be operable to provide an axial force to the coiled tubing string and thus the tool string 100 as it is run into the primary wellbore 5. In one embodiment, the conveyance member 10 may include a jointed tubing string, a string of continuous rods, and/or a wireline that is provided from a platform at the surface of the primary wellbore 5. In one embodiment, one or more fluids may be supplied from the surface, through the conveyance member 10, to the tool string 100 for operation of one or more components of the tool string 100. In one embodiment, a signal may be communicated from the surface, through the conveyance member 10, to the tool string 100 for operation of one or more components of the tool string 100. In one embodiment, the tool string 100 may include a connection assembly 20, an orientation assembly 30, a measurement assembly 40, a deflection assembly 50, a sub assembly 60, and a guide assembly 70. [0012] The tool string 100 may be coupled to the conveyance member 10 by the connection assembly 20. In one embodiment, the connection assembly 20 may include any type of motorhead assembly known by one of ordinary skill in the art. The connection assembly 20 may be operable to provide a sealed and/or a high-strength (tensile, torsional, compressive) connection between the conveyance member 10 and the tool string 100. In one embodiment, the connection assembly 20 may include a tubular member having a bore disposed therethrough, and may include one or more seals and/or slips for connection with the conveyance member 10. In one embodiment, the connection assembly 20 may include one or more valves, such as a flapper valve or a check valve, operable to control fluid flow through the connection assembly 20. In one embodiment, the connection assembly 20 may include a safety disconnect operable to disconnect the tool string 100 from the conveyance member 20 in the event of an emergency, such as if the tool string 100 becomes stuck in the primary wellbore 5. In one embodiment, the connection assembly 20 may include a circulation sub operable to isolate a lower portion of the tool string 100 from fluid flow, while maintaining fluid circulation through an upper portion of the tool string 100 and the primary wellbore 5.

[0013] The connection assembly 20 may also be connected to the orientation assembly 30. The orientation assembly 30 may include a tubular member having a bore disposed therethrough, and may be selectively actuatable using fluid pressure to orient the lower portion of the tool string 100. In one embodiment, the orientation assembly 30 may include a hydraulic ratcheting device that is operable to rotate the lower portion of the tool string 100 about the longitudinal axis of the tool string 100. The orientation assembly 30 may be operable to index the lower portion of the tool string 100 to one or more fixed intervals between 0 degrees and 360 degrees about the longitudinal axis of the tool string 100. Pressurized fluid may be supplied through the orientation assembly 30 to actuate the assembly, thereby indexing (rotating) the lower portion of the tool string 100 one or more degrees. In one embodiment, the orientation assembly 30 may automatically reset by decreasing the fluid pressure in the assembly. In this manner, pressurized fluid may be repeatedly supplied through the orientation assembly 30 to index the lower portion of the tool string through a 360 degree interval. [0014] The measurement assembly 40, also known as a measurement-while- drilling device, may be connected to the orientation assembly 30. The measurement assembly 40 may include a tubular member having a bore disposed therethrough. The measurement assembly 40 may be operable to measure one or more downhole characteristics, such wellbore inclination and azimuth (direction). In one embodiment, the measurement assembly 40 may be operable to measure wellbore drift within an inclination range of 0 degrees to 90 degrees with .25 degree increments, and wellbore direction with azimuth readings having 1 degree resolution. The measurement assembly 40 may also be operable to communicate a signal corresponding to the measured downhole characteristics real-time to an operator at the wellbore surface. The signal may be decoded and the measured results may be displayed real-time on a monitor or other type of display screen. In one embodiment, the signal (and thus the measured downhole characteristics) may be communicated real-time via mud- pulse telemetry, electromagnetic telemetry, and/or other telemetry methods known by one of ordinary skill in the art. The measurement assembly 40 may also include a power source, a microprocessor, a data acquisition system, and/or one or more sensors for measuring a variety of downhole characteristics, including wellbore and/or tool string 100 depth, inclination, and direction. In one embodiment, the measurement assembly 40 may be operable to measure the depth, inclination, and azimuth of one or more portions of the tool string 100, including the direction of the tool string 100 face. In one embodiment, the measurement assembly 40 may be operable to measure the orientation of a fixed point on the tool string 100 relative to gravity, magnetic and/or true north, or other known constant. In one embodiment, the measurement assembly 40 may be operable to measure the orientation of the face of the tool string 100 and compare the measured tool string face to a fixed reference point, also known as a "tie-in point," on the tool string 100 to determine the angular direction that the tool string 100 is facing downhole. In one embodiment, the measurement assembly 40 may be operable to measure the inclination of one or more portions of the tool string 100 downhole. The measured inclination of the tool string 100 may be used as a measurement of the inclination of the wellbore at that location downhole. In one embodiment, pressurized fluid may be supplied through the measurement assembly 40 to selectively activate the assembly to measure a downhole characteristic and communicate the measured downhole characteristic to an operator at the surface of the wellbore. [0015] The deflection assembly 50, also known as a kick-over knuckle joint, may be connected to the measurement assembly 40. The deflection assembly 50 may include a tubular member having a bore disposed therethrough. The deflection assembly 50 may be operable to tilt or deflect (i.e. "kick-over") the lower portion of the tool string 100 in the direction of a lateral wellbore. Pressurized fluid may be used to selectively actuate the deflection assembly 50 to deflect the lower portion of the tool string 100 at an angle of about 3 degrees to about 30 degrees, 45 degrees, or 60 degrees from the longitudinal axis of the tool string 100. In one embodiment, the deflection assembly 50 may be automatically reset by decreasing the fluid pressure in the assembly.

[0016] The sub assembly 60 may be connected to the deflection assembly 50, and the guide assembly 70 may be connected to the sub assembly 60. The sub and guide assemblies 60, 70 include the lower portions of the tool string 100 that are deflected out of alignment with the longitudinal axis of the tool string 100 by the deflection assembly 50. The sub and guide assembles 60, 70 may each include a tubular member have a bore disposed therethrough. The sub assembly 50 is operable to provide adequate length to the lower portion of the tool string 100 to sufficiently deflect it into a lateral wellbore, taking into account the angle of inclination from the primary wellbore 5, the diameter of the primary wellbore 5, and/or the diameter of the tool string 100. For example, the sub assembly 50 may need to be longer when in wellbores having larger inner diameters than when in smaller diameter wellbores. In one embodiment, the sub assembly 50 may be adjustable in length, for example, by telescoping, and/or may be shaped to have some curvature to facilitate entry into a lateral wellbore. The guide assembly 70 may include a guide nose to direct the tool string 00 into the primary and/or lateral wellbores; one or more ports, such as jetting nozzles, to allow fluid flow therethrough in all radial directions; and one or more flutes disposed on its outer surface to allow fluid flow around the outer diameter of the guide assembly 70.

[0017] In one embodiment, the tool string 100 may be lowered into one or more primary and/or lateral wellbores using a wireline conveyance member 10. In one embodiment, the tool string 100 may include a tractor member configured to move the tool string 100 through a wellbore having an inclined and/or horizontal trajectory. In one embodiment, the tool string 100 may be lowered into one or more primary and/or lateral wellbores using a coiled tubing conveyance member 10 with a wireline disposed through the coiled tubing conveyance member 10. The coiled tubing conveyance member 10 may be used to move the tool string 100 through a wellbore having an inclined and/or horizontal trajectory, while the wireline may be used to communicate a signal to one or more components of the tool string 100. In one embodiment, the connection assembly 20, the orientation assembly 30, the measurement assembly 40, the deflection assembly 50, the sub assembly 60, and/or the guide assembly 70 may be operable using electrical power. In one embodiment, an electrical signal may be communicated via the wireline conveyance member 10 to the orientation assembly 30, thereby actuating the orientation assembly 30 to orient the lower portion of the tool string 100. In one embodiment, the tool string 100 may include a selectively actuatable anchoring mechanism to secure a portion of the tool string 100 in the wellbore while another portion of the tool string 100 is rotated by the orientation assembly 30. In one embodiment, an electrical signal may be communicated via the wireline conveyance member 10 to the measurement assembly 40, thereby actuating the measurement assembly 40 to measure one or more downhole characteristics. In one embodiment, an electrical signal may be communicated via the wireline conveyance member 10 to the deflection assembly 50, thereby actuating the deflection assembly 50 to deflect the lower portion of the tool string 100. The orientation assembly 30, the measurement assembly 40, and/or the deflection assembly 50 may communicate a signal via the wireline conveyance member 10 to an operator to confirm operation of the assembly. Other forms of wired and/or wireless communication methods may be used with the embodiments described herein.

[0018] Referring now to Figures 1-5, an embodiment for locating and entering a lateral wellbore from a primary wellbore is illustrated. The tool string 100 is shown disposed in the primary wellbore 5, a portion of which may be lined with casing 15 that is cemented therein.- The primary wellbore 5 may be a vertical wellbore, a horizontal wellbore, and/or an angled wellbore between vertical and horizontal. A first lateral wellbore 25 and a second lateral wellbore 35 extend from the primary wellbore 5 at a first junction 23 and a second junction 33, respectively. The first and second lateral wellbores 25, 35 may be open-hole or may be lined with casing. In one embodiment, the first fateral wellbore 25 may drilled to a depth X with an azimuth of about 270 degrees and an inclination of about 88 degrees throughout the wellbore. In one embodiment, the second lateral wellbore 35 may drilled to a depth Y with an azimuth of about 250 degrees and an inclination of about 82 degrees throughout the wellbore.

[0019] A "primary wellbore" may include any wellbore that originates from the surface (including on-land, off-shore, and/or subsea applications) and/or any wellbore that is in communication with a lateral wellbore. A "lateral wellbore" may include any wellbore that intersects another wellbore. Inclination of a wellbore may be defined herein as the angle of the wellbore defined by a tangent line and a vertical line; the vertical line being substantially parallel to the direction of earth's gravity. In one embodiment, 0 degree inclination is vertical and 90 degree inclination is horizontal. Azimuth of a wellbore may be defined herein as the angle of the wellbore direction as projected to a horizontal plane and relative to true north and/or magnetic north. In one embodiment, 0 degree azimuth coincides with North, 90 degree azimuth with East, 180 degree azimuth with South, and 270 degree azimuth with West. The depth of a wellbore may be defined herein as an actual depth and/or a true vertical depth. In one embodiment, the actual depth is the depth of a point in the wellbore as measured along the path of the wellbore. In one embodiment, the true vertical depth is the absolute vertical distance from a point in the wellbore to a point at the surface. The depth of one or more points along the length of the wellbore can be measured and used with the embodiments described herein.

[0020] The downhole characteristics and the existing survey data as described herein may include measurements of and other information regarding the wellbores, the formation surrounding the wellbores, and/or one or more components of the tool string 100. In one embodiment, the downhole characteristics and existing survey data may include formation density, formation porosity/permeability, formation resistivity, formation fluids, and/or other rock and petro-physical properties. In one embodiment, the downhole characteristics and existing survey data may include inclination, azimuth, and/or depth of the wellbores and/or one or more components of the tool string. In one embodiment, the downhole characteristics and existing survey data may include the location, such as the depth, of a casing, the location a casing collar, the location of an RFID tag, the location of a PIP tag, and/or the location of other identifying "markers" in the wellbores. In one embodiment, the downhole characteristics and existing survey data may include the emission of radiation and/or a gamma ray log at a location in the wellbores. In one embodiment, the downhole characteristic and existing survey data may include the absence of one or more downhole characteristics and/or existing survey data of the wellbores. For example, the absence of a downhole characteristic when a measurement is taken at a particular location in the primary and/or lateral wellbores may be used to verify that the tool string 100 is and/or is not in a specific wellbore. [0021] As illustrated in Figure 1 , the tool string 100 may be run into the primary wellbore 5 using the conveyance member 10. During run-in, the lower portion of the tool string 100 may be maintained at an angle substantially coincident with the longitudinal axis of the upper portion of the tool string 100. The depth that the tool string 100 is located within the primary wellbore 25 may be continuously monitored and measured during run-in from the surface and/or using the measuring assembly 40. The tool string 100 may be positioned in the primary wellbore 5 at a location adjacent to the first junction 23. In one embodiment, the tool string 100 may be positioned in the primary wellbore 5 at a location ahead of, beyond, or next to the first junction 23. In one embodiment, existing survey data of the primary wellbore 5 may be used to approximate the depth at which the tool string 100 is to be lowered to position the tool string 100 within close proximity to the first junction 23. In one embodiment, existing survey data of the first and/or second lateral wellbores 25, 35, as well as any other lateral wellbores, may be used to confirm that the tool string 100 is not located in a lateral wellbore, thereby verifying that the tool string 100 is located in the primary wellbore 5.

[0022] As illustrated in Figure 2, when the tool string 100 is positioned at the desired depth relative to the first junction 23, the lower portion of the tool string 100 may be deflected with respect to the longitudinal axis of the upper portion of the tool string 100. In one embodiment, pressurized fluid may be supplied to the deflection assembly 50 (from the surface via the conveyance member 10) until a predetermined amount of pressure actuates the deflection assembly 50 to deflect the sub and guide assemblies 60, 70 with respect to the longitudinal axis of the upper portion of the tool string 100. The lower portion of the tool string 100 may be maintained in the deflected position, with or without maintaining fluid circulation therethrough. In one embodiment, the guide assembly 70 may contact the inner surface of the primary wellbore 5, which may constrain and prevent it from further deflection and which may force the upper potion of the tool string 100 toward an opposing side of the inner surface of the primary wellbore 5.

[0023] The measurement assembly 40 may be selectively activated to measure one or more downhole characteristics, such as the inclination and the azimuth of the primary wellbore 5, the first lateral wellbore 25, and/or one or more portions of the tool string 100. In one embodiment, the measurement assembly 40 may be selectively actuated to measure the angular direction that a lower portion of the tool string 100, such as a tool face of the guide assembly 70, is facing. The angular direction of the lower portion of the tool string 100 may be compared to a fixed reference point, such as a reference point on the tool string 100, to determine the angular direction that the lower portion of the tool string 100 is facing at the location in the primary wellbore 5. In one embodiment, the measurement assembly 40 may be selectively actuated to measure the angle of inclination of an upper portion of the tool string 00, such as a portion above the deflection assembly 50. The angle of inclination of the upper portion of the tool string 100 may correspond to the angle of inclination of the primary wellbore 5 at that location. In one embodiment, pressurized fluid may be supplied through the measurement assembly 40 (from the surface via the conveyance member 10) to activate the measurement assembly 40 and to generate a signal corresponding to the measured downhole characteristics. The measurement assembly 40 may communicate the signal corresponding to the measured downhole characteristics to an operator at the surface of the primary wellbore 5. The signal may be sent using electronic telemetry, mud-pulse telemetry, electromagnetic telemetry, and/or other remote communication methods. The signal may be converted to display the measured downhole characteristics on a monitor or other type of display screen. The measured downhole characteristics may be compared to existing survey data, such as the angular direction and inclination of the primary, first lateral, and/or second lateral wellbores 5, 25, 35. [0024] As illustrated in Figure 3, the lower portion of the tool string 100 may be rotated using the orientation assembly 30 in the direction of the first lateral wellbore 25. In one embodiment, pressurized fluid may be supplied to the orientation assembly 30 (from the surface via the conveyance member 10) until a predetermined amount of pressure actuates the orientation assembly 30 to rotate the lower portion of the tool string 100 relative to the longitudinal axis of the upper portion of the tool string 100. In one embodiment, pressurized fluid may be repeatedly pumped to the orientation assembly 30 to index the lower portion of the tool string 100 until the sub and guide assemblies 60, 70 are in alignment with the angular direction of the first lateral wellbore 25. The lower portion of the tool string 100 may be maintained in each indexed angular position, with or without maintaining fluid circulation therethrough. In one embodiment, the deflection assembly 50 may also be actuated to deflect the lower portion of the tool string 100 in alignment with the angle of inclination of the first lateral wellbore 25, limited only by contact with the inner surface of the primary wellbore 5. The measurement assembly 40 may continuously monitor, measure, and communicate the one or more downhole characteristics described above as the tool string 100 is oriented and directed into alignment with the first lateral wellbore 25.

[0025] In one embodiment, the tool string 100 may be located at a position in the primary wellbore ahead of the first junction 23. The tool string 100 may then be deflected and/or oriented as described above in the direction of the first lateral wellbore 25. The tool string 100 may then be lowered to the location of the first junction 23 and directed into the first lateral wellbore 25. The depth that the tool string 100 is located within the primary wellbore 25 may be continuously monitored and measured from the surface and/or downhole and compared to existing survey data of the location of the first and/or second junctions 23, 33, and/or the primary and/or lateral wellbores 5, 25, 35.

[0026] In one embodiment, the tool string 100 may be located at a position in the primary wellbore beyond or below the first junction 23. The tool string 100 may then be deflected and/or oriented as described above in the direction of the first lateral wellbore 25. The tool string 00 may be raised to the location of the first junction 23 and then directed into the first lateral wellbore 25. The depth that the tool string 100 is located within the primary wellbore 25 may be continuously monitored and measured from the surface and/or downhole and compared to existing survey data of the location of the first and/or second junctions 23, 33, and/or the primary and/or lateral wellbores 5, 25, 35. [0027] In one embodiment, the tool string 100 may be located at a position in the primary wellbore next to the first junction 23. The tool string 100 may then be deflected and/or oriented as described above in the direction of the first lateral wellbore 25. In one embodiment, the tool string 100 may be located relative to the first junction 23 so that a lower portion of the tool string 100 may be deflected directly into the first lateral wellbore 25. The tool string 100 may then be oriented or further oriented if necessary and directed into the first lateral wellbore 25. The depth that the tool string 100 is located within the primary wellbore 25 may be continuously monitored and measured from the surface and/or downhole and compared to existing survey data of the location of the first and/or second junctions 23, 33, and/or the primary and/or lateral wellbores 5, 25, 35.

[0028] As illustrated in Figure 4, when the lower portion of the tool string 100 is oriented and deflected in the desired position, the tool string 100 may be moved into the first lateral wellbore 25. The depth, inclination, and/or direction of the tool string 100 may be adjusted as it enters the first lateral wellbore 25 by comparing one or more measured downhole characteristics to existing survey data of the primary, first lateral, and/or second lateral wellbores 5, 25, 35. In this manner, the tool string 100 may accurately locate, identify, and enter the first lateral wellbore 25.

[0029] As illustrated in Figure 5, the measurement assembly 40 may continue to measure one or more downhole characteristics as it enters into the first lateral wellbore 25, and may communicate the measured downhole characteristics to the operator at the surface of the primary wellbore 5. The measured downhole characteristics can be compared to existing survey data to verify entry into the first lateral wellbore 25 and/or verify non-entry into the second lateral wellbore 35. For example, the measured angle of inclination and azimuth of the tool string 100 and the first lateral wellbore 25 at one or more locations within the first lateral wellbore 25 can be compared to existing survey data to verify that the tool string 100 has entered and is located in the first lateral wellbore 25. In one embodiment, the true vertical depth of the wellbores and the depth of the wellbores as measured from the surface when running the tool string 100 into the wellbores may also be used to verify the location of the tool string 100 in the primary wellbore 5 and/or first lateral wellbore 25 in a similar manner. If the measured downhole characteristics correspond with the existing survey data of the first lateral wellbore 25 at one or more locations within the first lateral wellbore 25, then the compared data can be used as a verification that the tool string 100 successfully identified and entered the first lateral wellbore 25. In one embodiment, the measured downhole characteristics may be compared to existing survey data of the primary wellbore 5 and/or one or more lateral wellbores that extend from the primary wellbore 5 to verify which wellbore the tool string 100 entered and which wellbore(s) the tool string 100 did not enter. In one embodiment, when the measured downhole characteristics and the existing survey data, of a target wellbore for example, are significantly different from each other, the compared data may act as a verification that the tool string 100 did not enter the target wellbore. The existing survey data of the primary and/or lateral wellbores 2, 25, 35 may have been generated during previous wellbore operations, such as the drilling operations utilized to form the wellbores.

[0030] In one embodiment, the tool string 100 may be configured to measure one or more downhole characteristics at the entrance of the lateral wellbores, e.g. at a location just past the wellbore junctions. The tool string 100 may not need to be lowered through the entire length of the lateral wellbore to verify entry or non-entry. Continuous monitoring and measuring of one or more downhole characteristics as the tool string 100 moves through the entrance of the lateral wellbore, and comparison with existing survey data may be sufficient to verify entry or non-entry when the measured survey data and the existing survey data are substantially coincident and/or substantially divergent. In one embodiment, after entry into the first or second lateral wellbores 25, 35 has been verified, the lower portion of the tool string 100 may be returned to an angle substantially coincident with the longitudinal axis of the upper portion of the tool string 100. [0031] In one embodiment, after verification of entry into the desired lateral wellbore, one or more lateral wellbore operations may be conducted in the lateral wellbore using the conveyance member 10 and the tool string 100. In one embodiment, a stimulation operation, e.g. pumping acid into the first lateral wellbore to stimulate recovery of hydrocarbons, or a remedial work operation, e.g. fishing out a stuck tool from the first lateral wellbore, may be performed. Other lateral wellbore operations may include jetting, logging, analyzing, cementing, etc. In one embodiment, the tool string 100 may include one or more components to conduct the lateral wellbore operation, such as stimulation tools, fishing tools, repair tools, etc. In one embodiment, these additional components may be located at least above the measuring assembly 40 within the tool string 100. In one embodiment, the tool string 100 may include one or more control valves, such as a sequencing valve, to control actuation of different tool string 100 components. The control valve may be operable to control fluid flow through the tool string 100 by diverting fluid into the annulus surrounding the tool string 100, based on the flow rate of fluid through the control valve. In one embodiment, the control valve may be preset to close at a specific flow rate by adjusting the strength of a biasing member, such as a spring, in the valve. In this manner, fluid may flow through the control valve at a first flow rate, and may be diverted to the annulus at a second flow rate that is greater than or less than the first flow rate.

[0032] In one embodiment, the tool string 100 may then be returned to the first junction 23 and the measurement assembly 40 may be activated to verify that the tool string 100 is located at the first junction 23. The above recited procedures may then be repeated to locate, identify, and/or enter the second lateral wellbore 35 using the tool string 00, as well as verify that the tool string 100 has entered the second lateral wellbore 35.

[0033] In one embodiment, a method of locating and entering a lateral wellbore that extends from a primary wellbore may include running a tool string into the primary wellbore via a conveyance member to a location ahead of, beyond, or next to a junction at the intersection of the primary and lateral wellbores. The tool string may include a connection assembly, an orientation assembly, a measurement assembly, a deflection assembly, a sub assembly, and a guide assembly. By monitoring/measuring the depth that the tool string is run into the primary wellbore and comparing the measured depth to existing survey data of at least one of the primary and lateral wellbores, the tool string may be located adjacent to the junction between the primary and lateral wellbores. Pressurized fluid may be supplied to the deflection assembly via the conveyance member to actuate the deflection assembly and thereby deflect a portion of the tool string at an angle relative to a longitudinal axis of the tool string. Pressurized fluid may be supplied to the measurement assembly via the conveyance member to actuate the measurement assembly and thereby measure the angular direction (azimuth) of the deflected portion of the tool string and the angle of inclination of a non-deflected portion of the tool string. The measured angular direction of the deflected portion of the tool string may be compared to a fixed reference point to determine the angular direction that the deflected portion of the tool string is facing. The angle of inclination of the non- deflected portion of the tool string may correspond to the angle of inclination of the wellbore at that location. The measured angular direction and angle of inclination may be compared to existing survey data, including an angular direction and angle of inclination of the primary and/or lateral wellbores. Pressurized fluid may be supplied to the orientation assembly via the conveyance member to actuate the orientation assembly and thereby orient the deflected portion of the tool string in the same angular direction as the lateral wellbore based on the existing survey data. Pressurized fluid may again be supplied to the measurement assembly via the conveyance member to actuate the measurement assembly and thereby re-measure the angular direction of the deflected portion of the tool string as stated above to verify that the deflected portion of the tool string is facing in the direction of the lateral wellbore. The tool string may be run in the direction of the lateral wellbore, while continuously monitoring/measuring the depth that the tool string is located. Pressurized fluid may again be supplied to the measurement assembly via the conveyance member to actuate the measurement assembly and thereby measure the angular direction of the deflected portion of the tool string, as well as the angle of inclination of a non-deflected portion of the tool string, as stated above. The measured angular direction, the measured angle of inclination, and/or the measured depth can be compared to existing survey data of the primary and/or any lateral wellbores to verify that the tool string has entered the desired lateral wellbore, as defined by the existing survey data.

[0034] In one embodiment, the procedures described herein with respect illustrations in Figures 1-5 may be configured into an automated process. A controller may be used to control the operation of the tool string 100 based on a pre-determined operational sequence. The controller may be programmed with or in communication with a database containing stored existing survey data of a primary wellbore and one or more lateral wellbores extending from the primary wellbore. A target lateral wellbore may be identified from the existing survey data and the controller may be programmed and/or instructed to located, identify, and enter the target lateral wellbore using the tool string 100. Using the existing survey data, the controller may direct run-in of the tool string 100 to a location near the primary wellbore and the target lateral wellbore junction as described above. The controller may actuate the measuring assembly 40, such as by directing fluid flow through the tool string 100, to measure one or more downhole characteristics, and may receive and compare the measured downhole characteristics to the existing survey data to verify that the tool string 100 is on the correct path to the target lateral wellbore. The controller may also actuate the orientation assembly 30 and/or the deflection assembly 50, such as by directing fluid flow through the tool string 100, to position the tool string 100 in the direction of the target lateral wellbore, based on the measured downhole characteristics and the existing survey data. Verification of entry into the target lateral wellbore may be provided by the controller, as it directs run-in of the tool string 100 into the lateral wellbore, actuates the orientation assembly 30, the measuring assembly 40, and the deflection assembly 50 as described above, and compares measured downhole characteristics to existing survey data at one or more locations within the entered lateral wellbore.

[0035] While the foregoing is directed to embodiments of the invention, other and further embodiments 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

Claims:

1. A method of locating and entering a lateral wellbore that extends from a primary wellbore, comprising:

running a tool string into the primary wellbore to a location adjacent to a junction between the primary and lateral wellbores using existing survey data of at least one of the primary and lateral wellbores;

deflecting a portion of the tool string at an angle relative to a longitudinal axis of the tool string;

measuring an inclination and an azimuth of the tool string;

comparing the measured inclination and azimuth to the existing survey data; running the tool string past the location adjacent to the junction and in a direction of the lateral wellbore based on the comparison of the measured inclination and azimuth to the existing survey data; and

measuring an inclination and an azimuth of the tool string after running it past the location adjacent to the junction and comparing the measured inclination and azimuth to the existing survey data to verify whether the tool string has entered the lateral wellbore.

2. The method of claim 1 , further comprising running the tool string into the primary wellbore using at least one of coiled tubing, jointed tubulars, continuous rod, and wireline.

3. The method of claim 1 , wherein the existing survey data of the primary and lateral wellbores includes at least one of inclination, azimuth, and depth.

4. The method of claim 1 , wherein the tool string includes a deflection assembly,_, and further comprising flowing fluid through the deflection assembly to actuate the deflection assembly to deflect the portion of the tool string.

5. The method of claim 1 , wherein the tool string includes a measurement assembly, and further comprising flowing fluid through the measurement assembly to actuate the measurement assembly to measure the inclination of a non-deflected portion of the tool string and the azimuth of the deflected portion of the tool string.

6. The method of claim 5, further comprising generating a signal corresponding to the measured inclination and azimuth.

7. The method of claim 6, further comprising communicating the signal to a remote location at a surface of the primary wellbore.

8. The method of claim 7, further comprising communicating the signal to the remote location using at least one of electronic telemetry, mud-pulse telemetry, and electromagnetic telemetry.

9. The method of claim 8, further comprising converting the signal and displaying the measured inclination and azimuth on a display screen.

10. The method of claim 1 , further comprising orienting the deflected portion of the tool string in the direction of the lateral wellbore based on the comparison of the measured inclination and azimuth to the existing survey data.

11. The method of claim 10, wherein the tool string includes an orientation assembly, and further comprising flowing fluid through the orientation assembly to actuate the orientation assembly to orient the deflected portion of the tool string in the direction of the lateral wellbore.

12. The method of claim 1 , further comprising re-measuring an inclination and an azimuth of the tool string after orienting the deflected portion of the tool string in the direction of the lateral wellbore, and comparing the re-measured inclination and azimuth to the existing survey data to verify that the deflected portion of the tool string is positioned in the direction of the lateral wellbore.

13. The method of claim 1 , further comprising continuously monitoring and measuring the depth at which the tool string is run into the primary wellbore, and comparing the measured depth to the existing survey data of the primary wellbore, including a true vertical depth and an actual depth of the primary wellbore.

14. The method of claim 13, wherein the depth that the tool string is run into the primary wellbore is monitored and measured from a surface of the primary wellbore.

15. The method of claim 1 , further comprising continuously monitoring and measuring the depth at which the tool string is run into the lateral wellbore, and comparing the measured depth to the existing survey data of the lateral wellbore, including a true vertical depth and an actual depth of the lateral wellbore.

16. The method of claim 15, wherein the depth that the tool string is run into the lateral wellbore is monitored and measured from a surface of the primary wellbore.

17. A method of locating and entering a lateral wellbore that extends from a primary wellbore, comprising:

locating a tool string adjacent to a junction between the primary and lateral wellbores;

measuring a first downhole characteristic at the junction using a measurement assembly of the tool string;

comparing the measured first downhole characteristic to existing survey data of at least one of the primary and lateral wellbores;

positioning the tool string in a direction of the lateral wellbore based on the comparison of the measured first downhole characteristic and the existing survey data;

moving the tool string in the direction of the lateral wellbore;

measuring a second downhole characteristic after the tool string has been moved in the direction of the lateral wellbore; and

comparing the measured second downhole characteristic to the existing survey data to verify whether the tool string has entered the lateral wellbore.

18. The method of claim 17, further comprising running the tool string into the primary wellbore using a conveyance member comprising at least one of coiled tubing, jointed tubulars, continuous rod, and wireline.

19. The method of claim 17, further comprising flowing fluid to the measurement assembly via a conveyance member to actuate the measuring assembly to measure the first downhole characteristic.

20. The method of claim 17, further comprising flowing fluid to an orientation assembly of the tool string via a conveyance member to actuate the orientation assembly to position the tool string in the direction of the lateral wellbore.

21. The method of claim 17, further comprising flowing fluid to a deflection assembly of the tool string via a conveyance member to actuate the deflection assembly to position the tool string in the direction of the lateral wellbore.

22. The method of claim 17, further comprising generating a signal corresponding to the measured first downhole characteristic using the measurement assembly and communicating the signal to a remote location at a surface of the primary wellbore.

23. The method of claim 22, further comprising communicating the signal to the remote location using at least one of electronic telemetry, mud-pulse telemetry, and electromagnetic telemetry.

24. The method of claim 17, wherein the first and second downhole characteristics include at least one of inclination, azimuth, and depth of at least one of a portion of the tool string, the primary wellbore, and the lateral wellbore.

25. The method of claim 17, further comprising continuously monitoring and measuring the depth at which the tool string is run into the primary and lateral wellbores, and comparing the measured depth to existing survey data of the primary and lateral wellbores, including a true vertical depth and an actual depth of the primary and lateral wellbores.

26. The method of claim 25, wherein the depth that the tool string is run into the primary and lateral wellbores is monitored and measured from a surface of the primary wellbore.

27. The method of claim 17, further comprising sending an electric signal to the measurement assembly via a wireline conveyance member to actuate the measuring assembly to measure the first downhole characteristic.

28. The method of claim 17, further comprising sending an electric signal to an orientation assembly of the tool string via a wireline conveyance member to actuate the orientation assembly to position the tool string in the direction of the lateral wellbore.

29. The method of claim 17, further comprising sending an electric signal to a deflection assembly of the tool string via a wireline conveyance member to actuate the deflection assembly to position the tool string in the direction of the lateral wellbore.

30. The method of claim 17, wherein the first and second downhole characteristics include at least one of a formation property, a location of a marker, and a radiation measurement.