WO2016053324A1

WO2016053324A1 - Multilateral access with real-time data transmission

Info

Publication number: WO2016053324A1
Application number: PCT/US2014/058546
Authority: WO
Inventors: Alejandro CHACON; Alexys Jose GONZALEZ; Ernesto BUSTAMANTE; Jose Antonio NOGUERA
Original assignee: Halliburton Energy Services, Inc.
Priority date: 2014-10-01
Filing date: 2014-10-01
Publication date: 2016-04-07
Also published as: RU2682288C2; AU2014407525A1; RU2017106740A; RU2017106740A3; US20170260834A1; NO20170315A1

Abstract

An example method includes introducing a downhole tool string into a main wellbore of a multilateral wellbore that includes a lateral wellbore that extends from the main wellbore. The downhole tool string includes a wand and a kickover knuckle joint coupled to the wand. A first measurement is obtained with an orientation measurement device, and an angular orientation of the kickover knuckle joint and the wand is aligned with the lateral wellbore as based on the first measurement. The downhole tool string is then advanced into the lateral wellbore and a second measurement is obtained with the orientation measurement device within the lateral wellbore. The second measurement is compared with known deviation survey measurements corresponding to the lateral wellbore to verifying a location of the downhole tool string in the lateral wellbore. A wellbore stimulation operation is then undertaken with the downhole tool string within the lateral wellbore.

Description

MULTILATERAL ACCESS WITH REAL-TIME DATA TRANSMISSION

BACKGROUND

[0001] The present disclosure relates to multilateral wellbore operations and, more particularly, to downhole tool strings having an orientation measurement device that can be used to locate lateral wellbores.

[0002] Operators seeking to produce hydrocarbons from subterranean formations often drill multilateral wells. Unlike conventional vertical wells, a multilateral well includes a primary wellbore and one or more lateral wellbores that branch from the primary wellbore. Although multilateral wells are often more expensive to drill and complete than conventional wells, multilateral wells are generally more cost-effective overall, as they usually maximize production of reservoirs and therefore have greater production capacity and higher recoverable reserves. Multilateral wells are also an attractive choice in situations where it is necessary or desirable to reduce the amount of surface drilling operations, such as when environmental regulations impose drilling restrictions.

[0003] Although multilateral wells may offer advantages over conventional wells, they may also involve greater complexity, which may pose additional challenges. One such challenge involves locating and entering a specific lateral wellbore that branches from a primary wellbore. A number of techniques have been developed for locating and entering lateral wellbores, including the installation of special jewelry in the casing at a junction of the lateral and primary wellbores. This jewelry allows the landing of a whipstock adjacent to the junction to force any subsequent tubing run into the primary wellbore into the desired lateral wellbore.

[0004] Another technique for locating and entering a lateral wellbore involves utilizing a downhole tool string that includes an indexing tool, a kickover knuckle joint attached to the lower end of the indexing tool, and a wand extension attached to the lower end of the kickover knuckle joint. The downhole tool string may first be lowered to the bottom of the primary wellbore to tag the bottom thereof and perform any desired treatment. After performing the treatment, the downhole tool string may then be raised to the estimated location of a junction between the primary and lateral wellbores. The kickover knuckle joint can be used to deflect the wand away from the central axis of the downhole tool string and fluid is pumped to the downhole tool string from a surface location, which will maintain the wand in contact with the wellbore, preventing it from fully kicking out. Upon locating the lateral wellbore, the tip of the wand is able to bend fully into the lateral wellbore and exhaust pressurized fluid from the downhole tool string, which may be sensed at the surface as a pressure drop, and thereby provide positive indication that the lateral wellbore has been located.

[0005] If the wand fails to locate the lateral wellbore, the downhole tool string is lowered again a certain amount of length in the primary wellbore and the indexing tool may be used to rotate the kickover knuckle joint and the wand to operate at a different angular orientation. The downhole tool string is then raised within the primary wellbore until the wand locates the lateral wellbore. This process is repeated until the wand positively locates the lateral wellbore.

[0006] As can be appreciated, this process can require a significant consumption of fluids needed to operate the downhole tool string through these repetitions, which can occur over the span of potentially several hours, as well as excessively fatiguing the coiled tubing workstring.

[0007] Moreover, in some cases, fluid venting from the downhole tool string may not reliably signal that a lateral wellbore has been located. In some instances, for example, the tip of the wand may not fully bend and vent even though it locates and enters a lateral wellbore. In other cases, the downhole tool string may vent when it is not in the lateral wellbore, inter alia, because the curvature of the conveyance (e.g., coiled tubing) above the downhole tool string may be sufficient to allow the wand to fully bend and vent. Because of the possibility of premature venting, once the operator believes that a lateral wellbore has been positively located, the downhole tool string is often lowered to the bottom of the lateral wellbore to tag the bottom thereof. This depth is then compared with the previously recorded depth of the primary wellbore and, if the two depths are identical, it can be surmised that a lateral wellbore has not been found, and the operator must repeat the procedure for locating the lateral wellbore.

[0008] The need to repeatedly tag the bottom of the primary and lateral wellbores may add undesirable delays and expense to lateral wellbore operations. Lateral wellbores that have a very similar bottom depth also pose an additional problem, as it might not be clear on which of the two laterals the coiled tubing and string are located. BRIEF DESCRIPTION OF THE DRAWINGS

[0009] The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, without departing from the scope of this disclosure.

[0010] FIG. 1 depicts a rigless well intervention system in which the principles of the present disclosure may be employed.

[0011] FIGS. 2A and 2B are progressive partial cross-sectional views of an exemplary downhole tool string.

[0012] FIG. 3 is a schematic flow chart of a method of locating a lateral wellbore. DETAILED DESCRIPTION

[0013] The present disclosure relates to multilateral wellbore operations and, more particularly, to a downhole tool strings having an orientation measurement device that can be used to locate lateral wellbores.

[0014] The embodiments described herein provide a system and method of locating a lateral wellbore of a multilateral wellbore and performing a wellbore stimulation in the lateral wellbore. According to the present disclosure, a downhole tool string includes an orientation measurement device that can provide real-time measurements of inclination, azimuth, and tool face direction as the downhole tool string advances downhole. The real-time measurements may be used to angularly align a wand included in the downhole tool string with the lateral wellbore, and subsequently verify that the downhole tool string has positively entered the lateral wellbore. This may prove advantageous in eliminating the need to pump excessive amounts of fluid to the downhole tool string and the wand in seeking the lateral wellbore, and may also reduce the time required to find the lateral wellbore. Moreover, the downhole tool string and associated conveyance may assume less fatigue since multiple cycling up and down within the wellbore can be avoided by implementing the principles of the present disclosure. Once the downhole tool has successfully entered the lateral wellbore, a wellbore stimulation operation such as acidizing, water conformance treatments, distributed temperature survey with fiber optics, abrasive perforating, amongst others.

[0015] Referring to FIG. 1, illustrated is an exemplary rigless well intervention system 100 that may employ the principles of the present disclosure, according to one or more embodiments. As illustrated, the rigless well intervention system 100 (hereafter "the system 100") may include a parent or main wellbore 102 and at least one lateral wellbore 104 that extends from the main wellbore 102. The main wellbore 102 may be a wellbore drilled from a surface location (not shown) to penetrate a subterranean formation 106, and the lateral wellbore 104 may intersect the main wellbore 102 at a junction 108 and may otherwise comprise a lateral or deviated wellbore drilled at an angle from the main wellbore 102. While the main wellbore 102 is shown as being oriented generally vertical, the main wellbore 102 may alternatively be oriented generally horizontal or at any angle between vertical and horizontal, without departing from the scope of the disclosure.

[0016] Both the main and lateral wellbores 102, 104 may be lined with a liner or a string of casing 110 and subsequently cemented in place, or may be left without any liner, which is called a "barefoot" completion. As known in the art, the string of casing 110 may comprise multiple lengths of tubular conduits or pipe secured together at their ends and extended into the main and lateral wellbores 102, 104.

[0017] The system 100 may further include a downhole tool string 112 that is able to be run into the main wellbore 102 on a conveyance 114 extending from the surface location (not shown). In some embodiments, the conveyance 114 may be coiled tubing or the like, and the surface location may include a wellhead installation (not shown) and a coiled tubing unit (not shown) . The coiled tubing unit may be configured to access the main wellbore 102 via the wellhead installation and thereby extend the downhole tool string 112 into the main wellbore 102. Accordingly, in at least one embodiment, the system 100 may be characterized as "rigless," meaning that a drilling rig or drilling service unit is not located nor required at the surface location. Rather, the main and lateral wellbores 102, 104 have already been drilled and completed, and the downhole tool string 112 may be selectively introduced into the main and/or lateral wellbores 102, 104 to undertake one or more wellbore stimulation operations, such as acidizing, water conformance treatments, distributed temperature survey with fiber optics, abrasive perforating, amongst others.

[0018] The downhole tool string 112 may include various components and devices used to undertake the wellbore stimulation operations. In some embodiments, for instance, the downhole tool string 112 may include at least an orienting sub 116, an orientation measurement device 118, a kickover knuckle joint 120, and a wand 122. In at least one embodiment, the downhole tool string 112 may further include at least one centralizer (not shown) used to radially centralize the downhole tool string 112 within the main and/or lateral wellbores 102, 104. The various components of the downhole tool string 112 may be connected to each other end to end with threaded connections. In all embodiments, the downhole tool string 112 may facilitate fluid communication through its entire length and thereby able to provide a fluid to the wand 122 from the conveyance 114.

[0019] The orienting sub 116 may include any known device used for rotating the components of the downhole tool string 112 about a central axis 124 of the downhole tool string 112. More particularly, the orienting sub 116 may be selectively activated to rotate the orientation measurement device 118, the kickover knuckle joint 120, and the wand 122 about the central axis 124. In other embodiments, as described below, the axial positions of the orienting sub 116 and the orientation measurement device 118 may be reversed, without departing from the scope of the disclosure.

[0020] Example devices that may be suitable as the orienting sub 116 include, but are not limited to, an indexing tool and a continuously run motor. An indexing tool may facilitate rotation of a predetermined number of degrees (e.g., 30°, 45°, etc.) about the central axis 124 upon actuating or being activated. The indexing tool may be activated using fluid pressure conveyed thereto via the conveyance 114. When the fluid pressure from the conveyance 114 is increased and subsequently released, the indexing tool may be configured to automatically rotate the predetermined number of degrees, and thereby alter the angular configuration of the components of the downhole tool string 112 located therebelow. In embodiments where the orienting sub 116 is a continuously run motor, the continuously run motor may provide selective 360° rotation about the central axis 124 of the downhole tool string 112. One of ordinary skill in the art with the benefit of this disclosure will be able to select and employ an appropriate orienting sub 116 for a particular application .

[0021] The orientation measurement device 118 may include one or more sensors configured to measure, detect, and otherwise determine the orientation of a known fixed point on the downhole tool string 112 relative to gravity, magnetic north, or other parsable environmental constants. In some embodiments, for example, the orientation measurement device 118 may comprise a measurement-while-drilling (MWD) tool, such as a MWD tool commercially available from Sperry Drilling and Halliburton Energy Services of Houston, Texas, USA. The orientation measurement device 118 may be configured to measure and report the real-time azimuth, inclination, and tool- face direction of the downhole tool string 112 and, more particularly, of the kickover knuckle joint 120 and the wand 122, in addition to temperature and gamma ray measurements.

[0022] The orientation measurement device 118 may also include a wellbore telemetry device 126 configured to communicate either wired or wirelessly with the surface location, thereby allowing a well operator to receive real-time measurements of the azimuth, inclination, and tool-face direction of the downhole tool string 112. The wellbore telemetry device 126 may be any downhole telemetering device known to those skilled in the art including, but not limited to, mud pulse telemetry, electromagnetic telemetry, acoustic telemetry, ultrasonic telemetry, electrical lines, fiber optic lines, radio frequency transmission, or any combination thereof.

[0023] The kickover knuckle joint 120 may be any suitable device adapted to deflect the wand 122 with respect to the central axis 124 of the downhole tool string 112. In some embodiments, the kickover knuckle joint 120 is a selectively activated knuckle joint, such as a hydraulic kickover joint available from NOV. Other suitable kickover knuckle joints 120 include, but are not limited to, restricted ball joints, pin joints, bourdon tubes, or an asymmetrically slotted member with internal pressurization means. One of ordinary skill in the art with the benefit of this disclosure should be able to select and implement the appropriate kickover knuckle joint 120 for a particular application .

[0024] In some embodiments, the kickover knuckle joint 120 may not bend or deflect until it is activated through fluid pressure conveyed thereto via the conveyance 114. Upon assuming fluid pressure, the kickover knuckle joint may be configured to bend or otherwise deflect from the central axis 124. Accordingly, activation of the kickover knuckle joint 120 may be controlled from the surface by controlling the hydraulic pressure conveyed to the kickover knuckle joint 120 via the conveyance 114.

[0025] The wand 122, also known as a nozzle probe, may be operatively coupled to the kickover knuckle joint 120 and otherwise located at the distal end of the downhole tool string 112. By activating the kickover knuckle joint 120, the wand 122 may be deflected from alignment with the central axis 124 to enter a lateral wellbore, such as the lateral wellbore 104. The wand 122 may exhibit a length sufficient to be deflected into the lateral wellbore 104 when it locates the junction 108. The wand 122 may be deflected with respect to the central axis 124 to a predetermined maximum deflection angle 128. The maximum deflection angle 128 of the wand 122 may depend on a number of factors, including the inner diameter of the main wellbore 102 and the axial length of wand 122. Generally, a suitable maximum deflection angle 128 for the wand 122 may be in the range from about 3° to about 30° from the central axis 124. In some embodiments, the kickover knuckle joint 120 may be configured to deflect the wand 122 about 15° from the central axis 124.

[0026] Exemplary operation of the downhole tool string 112 in locating and entering the lateral wellbore 104 is now provided. The general location of the junction 108 and its angular orientation within the main wellbore 102 may be known from prior survey measurements taken while drilling and completing the main and lateral wellbores 102, 104. Upon building the downhole tool string 112, the angular orientation of the kickover knuckle joint 120 may also be noted and known relative to the orientation measurement device 118. Therefore, using the measurements obtained by the orientation measurement device 118 as the downhole tool string 112 is conveyed downhole, the angular orientation of the kickover knuckle joint 120 within the main wellbore 102 may be calculated and otherwise known. The angular orientation of the kickover knuckle joint 120 may be reoriented as needed so that the wand 122 is able to angularly align with the lateral wellbore 104. Changing the angular orientation of the kickover knuckle joint 120 may be accomplished by activating the orienting sub 116 to rotate the kickover knuckle joint 120 and the wand 122 the predetermined number of degrees (e.g., 30°, 45°, etc.) . [0027] As the downhole tool string 112 is conveyed downhole within the main wellbore 102, the orientation measurement device 118 may be continuously obtaining measurements and reporting the same in real-time to the surface location using the wellbore telemetry device 126. As a result, a well operator may be apprised of the real-time location of the downhole tool string 112 as it nears the junction 108. Upon reaching the junction 108, the angular orientation of the wand 122 may be adjusted so that it is able to align with the lateral wellbore 104. The correct angular orientation of the wand 122 may be confirmed in real-time with the orientation measurement device 118 or otherwise as the wand 122 bends or deflects into the lateral wellbore 104 and vents fluid pressure, which may be sensed at the surface location.

[0028] Once the wand 122 is angularly oriented with the lateral wellbore 104, the downhole tool string 112 may be advanced into the lateral wellbore 104 and the orientation measurement device 118 may again be used to verify the present location of the downhole tool string 112. More particularly, after entering the lateral wellbore 104, the location of the downhole tool string 112 may be uniquely validated in real-time by obtaining new inclination, azimuth, and tool-face direction measurements with the orientation measurement device 118 and comparing those measurements with known deviation survey measurements corresponding to the lateral wellbore 104. If the new measurements and the deviation survey measurements fail to match, that may indicate that the downhole tool string 112 failed to enter the lateral wellbore 104 and instead remains in the main wellbore 102. If this occurs, the lateral location procedure will be repeated. If the present measurements and the deviation survey measurements match, however, that may provide positive indication that the downhole tool string 112 has successfully entered the lateral wellbore 104. While in the lateral wellbore 104, the well operator may proceed to undertake various wellbore stimulation operations, such as acidizing, water conformance treatments, distributed temperature survey with fiber optics, abrasive perforations, amongst others.

[0029] Referring now to FIGS. 2A and 2B, illustrated are progressive partial cross-sectional views of an exemplary downhole tool string 200, according to one or more embodiments. The downhole tool string 200 may be the same as or similar to the downhole tool string 112 of FIG. 1 and therefore may be best understood with reference thereto, where like numerals indicate like components not described again. FIG. 2A depicts an exploded view of the upper portions of the downhole tool string 200, and FIG. 2B depicts an exploded view of the lower portions of the downhole tool string 200. As indicated by the exploded views, the various components of the downhole tool string 200 may be threadably coupled. In other embodiments, however, one or more of the components of the downhole tool string 200 may be coupled using any other attachment means including, but not limited to, mechanical fasteners, welding, and brazing.

[0030] Referring first to FIG. 2A, the downhole tool string 200 may include a connector 202 used to couple the downhole tool string 200 to a conveyance, such as the conveyance 114 of FIG. 1. The downhole tool string 200 may further include a motor head assembly 204 and a sequencing flow sub 206 positioned between the connector 202 and the orienting sub 116. The motor head assembly 204 may include one or more check valves 210 (shown as a first check valve and a second check valve) configured to prevent fluid from flowing uphole and otherwise back to the conveyance 114 from the downhole tool string 200. Rather, the check valves 210 may be configured to allow fluid to proceed downhole through the downhole tool string 200.

[0031] The motor head assembly 204 may further include a hydraulic disconnect 208a, a circulation port 208b, and a burst disc 212. The hydraulic disconnect 208a may allow lower portions of the downhole tool string 200 below the motor head assembly 204 to be disconnected in the event the downhole tool string 200 becomes stuck in the main or lateral wellbores 102, 104 (FIG. 1) . The circulation port 208b may provide an outlet for fluids conveyed to the downhole tool string 200 from the conveyance 114 (FIG. 1) in the event the lower portions of the downhole tool string 200 below the motor head assembly 204 become stuck. The burst disc 212 may allow fluid circulation through the downhole tool string 200 in the event the lower components of the downhole tool string 200 below the motor head assembly 204 become plugged. Penetrating or breaking the burst disc 212 may result in fluid communication to the annulus surrounding the downhole tool assembly 200 via the motor head assembly 204.

[0032] The sequencing flow sub 206 may be activated to divert fluid flow received from the conveyance 114 (FIG. 1) so that no fluid flows to the components of the downhole tool string 200 below the sequencing flow sub 206. Following its actuation, any fluid introduced into the sequencing flow sub 206 may be diverted and ejected from the sequencing flow sub 206 via one or more side nozzles 207. As will be appreciated, the sequencing flow sub 206 may allow stimulation fluids, such as abrasive fluids and acids, to be injected into the main and lateral wellbores 102, 104 (FIG. 1) while undertaking the various wellbore stimulation operations mentioned herein. The mechanism of activation of the sequencing flow sub 206 is based on flow rate of the fluid pumped from the surface. The sequencing flow sub 206 can be setup with several flow rate activation settings, depending on the specific need. Once the flow exceeds the predetermined rate, the flow to the tools below the sequencing flow sub 206 is stopped via a spring-operated mechanism or similar, and a sleeve, or another similar device, shifts to expose the nozzles 207, thus allowing flow to come out of the nozzles 207.

[0033] In some embodiments, a cross-over sub 214 may interpose and otherwise be positioned between the orienting sub 116 and the orientation measurement device 118. In other embodiments, however, the cross-over sub 214 may be omitted and the orienting sub 116 may instead be directly coupled to the orientation measurement device 118, without departing from the scope of the disclosure.

[0034] Referring to FIG. 2B, in some embodiments, the downhole tool string 200 may further include a gauge carrier 216. In at least one embodiment, a cross-over sub 218 may interpose and otherwise be positioned between the gauge carrier 216 and the orientation measurement device 118 (FIG. 2A) . In other embodiments, however, the cross-over sub 218 may be omitted and the gauge carrier 216 may instead be directly coupled to the orientation measurement device 118, without departing from the scope of the disclosure.

[0035] The gauge carrier 216 may include various sensors and gauges used to measure downhole parameters such as, but not limited to, pressure and temperature. The sensors and gauges included in the gauge carrier 216 may further include a gamma ray sensor and a casing collar locator.

[0036] As illustrated, an optional cross-over sub 220 may interpose and otherwise be positioned between the gauge carrier 216 and the kickover knuckle joint 120. Moreover, in some embodiments, the downhole tool string 200 may further include an extension arm 222 used to extend the reach or axial length of the wand 122 located at the distal end of the downhole tool string 200. As will be appreciated, the extension arm 222 may prove advantageous in embodiments where the diameter of the main or lateral wellbores 102, 104 (FIG. 1) are large. In other embodiments, the extension arm 222 may be omitted. As illustrated in FIG. 2B, the wand 122 may include one or more vents 224 (shown as vents 224a and 224b) defined therein. The vents 224a, b may provide outlets used to vent fluid pressure from the downhole tool string 220 when the wand 122 locates and deflects into a lateral wellbore (e.g., the lateral wellbore 104 of FIG. 2) .

[0037] In the illustrated embodiment of FIGS. 2A and 2B, the orientation measurement device 118 is depicted as being positioned below the orienting sub 116 along the axial length of the downhole tool string 200 and thereby able to obtain real-time inclination and tool-face data closer to the kickover knuckle joint 120. In other embodiments, however, the orientation measurement device 118 may alternatively be positioned above the orienting sub 116, without departing from the scope of the disclosure. In such embodiments, the angular orientation of the kickover knuckle joint 120 may nonetheless be known or otherwise calculated by knowing the degrees of rotation per indexing cycle of the orienting sub 116 and the number of times the orienting sub 116 has been activated.

[0038] Referring now to FIG. 3, illustrated is a schematic flow chart of an exemplary method 300 of locating a lateral wellbore, according to one or more embodiments. The method 300 may be accomplished using either of the downhole tool strings 112, 200 described herein in locating and entering one or more lateral wellbores, such as the lateral wellbore 104 of FIG. 1. According to the method 300, a downhole tool string may be introduced into a main wellbore of a multilateral wellbore, as at 302. The multilateral wellbore may include a lateral wellbore that extends from the main wellbore at a junction. Moreover, the downhole tool string may include a wand and a kickover knuckle joint coupled to the wand.

[0039] A first measurement may be obtained with an orientation measurement device included in the downhole tool string, as at 304. The first measurement may include at least one of an azimuth, an inclination, and a tool- face direction of the downhole tool string. The first measurement may be communicated to a surface location in real time with a wellbore telemetry device communicably coupled to the orientation measurement device. The angular orientation of the kickover knuckle joint and the wand may then be aligned with the lateral wellbore as based on the first measurement, as at 306. In some embodiments, this may include activating an orienting sub included in the downhole tool string, and thereby changing the angular orientation of the kickover knuckle joint and the wand.

[0040] The downhole tool string may then be advanced into the lateral wellbore to obtain a second measurement with the orientation measurement device, as at 308. The second measurement may be obtained while the downhole tool string is positioned in the lateral wellbore and may include at least one of the azimuth, the inclination, and the tool-face direction of the downhole tool string. The second measurement may be communicated to the surface location in real time with the wellbore telemetry device.

[0041] The second measurement may then be compared with known deviation survey measurements corresponding to the lateral wellbore, as at 310. Comparing the second measurement with the known deviation survey measurements may verify a location of the downhole tool string within the lateral wellbore. Once it is verified that the downhole tool string is located within the lateral wellbore, one or more wellbore stimulation operations may be undertaken with the downhole tool string while positioned in the lateral wellbore, as at 312. Undertaking the one or more wellbore stimulation operations may include activating a sequencing flow sub included in the downhole tool string to prevent a stimulation fluid from passing into at least an orienting sub, the kickover knuckle joint, and the wand, and diverting the stimulation fluid out of the sequencing flow sub. Undertaking the one or more wellbore stimulation operations may further include at least one treating a portion of the lateral wellbore such as acidizing, water conformance treatments, distributed temperature survey with fiber optics, abrasive perforating, amongst others. The foregoing steps of 302 - 312 may then be repeated at a second lateral wellbore within the multilateral wellbore, as at 314.

[0042] Embodiments disclosed herein include:

[0043] A. A method that includes introducing a downhole tool string into a main wellbore of a multilateral wellbore, the multilateral wellbore including a lateral wellbore that extends from the main wellbore at a junction, and the downhole tool string including a wand and a kickover knuckle joint coupled to the wand, obtaining a first measurement with an orientation measurement device included in the downhole tool string, the first measurement including at least one of an azimuth, an inclination, and a tool-face direction of the downhole tool string, aligning an angular orientation of the kickover knuckle joint and the wand with the lateral wellbore as based on the first measurement, advancing the downhole tool string into the lateral wellbore and obtaining a second measurement with the orientation measurement device while the downhole tool string is positioned in the lateral wellbore, the second measurement including at least one of the azimuth, the inclination, and the tool-face direction of the downhole tool string, comparing the second measurement with known deviation survey measurements corresponding to the lateral wellbore and thereby verifying a location of the downhole tool string in the lateral wellbore, and undertaking one or more wellbore stimulation operations with the downhole tool string while positioned in the lateral wellbore.

[0044] B. A rigless well intervention system that includes a main wellbore having at least a portion thereof lined with casing, a lateral wellbore that extends from the main wellbore at a junction, at least a portion of the lateral wellbore being lined with casing, a downhole tool string extendable within the main wellbore on a conveyance from a surface location and having a central axis, the downhole tool string including a wand and a kickover knuckle joint coupled to the wand to deflect the wand from the central axis, an orienting sub that adjusts an angular orientation of at least the kickover knuckle joint and the wand about the central axis, an orientation measurement device that measures one or more of an azimuth, an inclination, and a tool-face direction of at least one of the kickover knuckle joint and the wand, a wellbore telemetry device communicably coupled to the orientation measurement device for communicating at least one of the azimuth, the inclination, and the tool-face direction to the surface location in real-time, and a sequencing flow sub that is actuatable to prevent a stimulation fluid from passing into at least the orienting sub, the kickover knuckle joint, and the wand, and instead divert the stimulation fluid out of the sequencing flow sub to undertake a wellbore stimulation operation in the lateral wellbore.

[0045] C. A downhole tool string that includes a wand, a kickover knuckle joint coupled to the wand to deflect the wand from a central axis, an orienting sub that adjusts an angular orientation of at least the kickover knuckle joint and the wand about the central axis, an orientation measurement device that measures one or more of an azimuth, an inclination, and a tool-face direction of at least one of the kickover knuckle joint and the wand, a wellbore telemetry device communicably coupled to the orientation measurement device for communicating at least one of the azimuth, the inclination, and the tool-face direction to a surface location in real-time, and a sequencing flow sub that is actuatable to prevent a stimulation fluid from passing into at least the orienting sub, the kickover knuckle joint, and the wand, and instead divert the stimulation fluid out of the sequencing flow sub to undertake a wellbore stimulation operation.

[0046] Each of embodiments A, B, and C may have one or more of the following additional elements in any combination : Element 1 : wherein aligning the angular orientation of the kickover knuckle joint and the wand with the lateral wellbore comprises activating an orienting sub included in the downhole tool string, and changing the angular orientation of the kickover knuckle joint and the wand with the orienting sub. Element 2 : wherein the downhole tool string further includes a sequencing flow sub, and wherein undertaking the one or more wellbore stimulation operations comprises activating the sequencing flow sub to prevent a stimulation fluid from passing into at least an orienting sub, the kickover knuckle joint, and the wand, and diverting the stimulation fluid out of the sequencing flow sub. Element 3 : wherein undertaking the one or more wellbore stimulation operations comprises at least one of acidizing a portion of the lateral wellbore and hydraulically fracturing a portion of the lateral wellbore. Element 4: wherein the downhole tool string further includes a wellbore telemetry device communicably coupled to the orientation measurement device, the method further comprising communicating the first and second measurements to the surface location in real-time. Element 5 : wherein communicating the first and second measurements to the surface location in real-time comprises operating the wellbore isolation device using at least one of mud pulse telemetry, electromagnetic telemetry, acoustic telemetry, ultrasonic telemetry, electrical lines, fiber optic lines, radio frequency transmission, and any combination thereof. Element 6: wherein the downhole tool string further includes a gauge carrier that includes one or more sensors or gauges, the method further comprising measuring one or more downhole parameters with the gauge carrier as the downhole tool string advances within the main or lateral wellbores. Element 7 : wherein the lateral wellbore is a first lateral wellbore and the junction is a first junction, the method further comprising retracting the downhole tool string from the first lateral wellbore and into the main wellbore, moving the downhole tool string within the main wellbore toward a second lateral wellbore that extends from the main wellbore at a second junction, obtaining a third measurement with the orientation measurement device, the first measurement including at least one of the azimuth, the inclination, and the tool-face direction of the downhole tool string, aligning the angular orientation of the kickover knuckle joint and the wand with the second lateral wellbore as based on the third measurement, advancing the downhole tool string into the second lateral wellbore and obtaining a fourth measurement with the orientation measurement device while the downhole tool string is positioned in the second lateral wellbore, the fourth measurement including at least one of the azimuth, the inclination, and the tool-face direction of the downhole tool string, comparing the fourth measurement with known deviation survey measurements corresponding to the second lateral wellbore and thereby verifying a location of the downhole tool string in the second lateral wellbore, and undertaking one or more wellbore stimulation operations with the downhole tool string while positioned in the second lateral wellbore. Element 8: wherein undertaking the one or more wellbore stimulation operations with the downhole tool string while positioned in the second lateral wellbore comprises at least one of acidizing a portion of the second lateral wellbore and hydraulically fracturing a portion of the second lateral wellbore.

[0047] Element 9 : wherein the conveyance is coiled tubing. Element 10 : wherein the orienting sub is an indexing tool that rotates a predetermined number of degrees about the central axis upon being activated. Element 11 : wherein the orientation measurement device comprises a measurement-while- drilling tool. Element 12 : wherein the wellbore telemetry device operates using at least one of mud pulse telemetry, electromagnetic telemetry, acoustic telemetry, ultrasonic telemetry, electrical lines, fiber optic lines, radio frequency transmission, and any combination thereof. Element 13 : wherein the stimulation fluid is at least one of a fracturing fluid and an acid.

[0048] Element 14 : wherein the orienting sub is an indexing tool that rotates a predetermined number of degrees about the central axis upon being activated. Element 15 : wherein the orientation measurement device comprises a measurement-while-drilling tool. Element 16 : wherein the wellbore telemetry device operates using at least one of mud pulse telemetry, electromagnetic telemetry, acoustic telemetry, ultrasonic telemetry, an electrical line, a fiber optic line, radio frequency transmission, and any combination thereof. Element 17 : wherein the stimulation fluid is at least one of a fracturing fluid and an acid. Element 18: further comprising a motor head assembly, and a gauge carrier that includes one or more sensors or gauges used to measure downhole parameters.

[0049] By way of non-limiting example, exemplary combinations applicable to A, B, and C include : Element 4 with Element 5; Element 7 with Element 8; Element 9 with Element 11; and Element 9 with Element 12.

[0050] Therefore, the disclosed systems and methods are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein . The particular embodiments disclosed above are illustrative only, as the teachings of the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein . Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present disclosure. The systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein . While compositions and methods are described in terms of "comprising," "containing," or "including" various components or steps, the compositions and methods can also "consist essentially of" or "consist of" the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, "from about a to about b," or, equivalently, "from approximately a to b," or, equivalently, "from approximately a-b") disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles "a" or "an," as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

[0051] As used herein, the phrase "at least one of" preceding a series of items, with the terms "and" or "or" to separate any of the items, modifies the list as a whole, rather than each member of the list {i.e., each item). The phrase "at least one of" allows a meaning that includes at least one of any one of the items, and/or at least one of any combination of the items, and/or at least one of each of the items. By way of example, the phrases "at least one of A, B, and C" or "at least one of A, B, or C" each refer to only A, only B, or only C; any combination of A, B, and C; and/or at least one of each of A, B, and C.

[0052] The use of directional terms such as above, below, upper, lower, upward, downward, left, right, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well.

Claims

CLAIMS What is claimed is:

1. A method, comprising:

introducing a downhole tool string into a main wellbore of a multilateral wellbore, the multilateral wellbore including a lateral wellbore that extends from the main wellbore at a junction, and the downhole tool string including a wand and a kickover knuckle joint coupled to the wand;

obtaining a first measurement with an orientation measurement device included in the downhole tool string, the first measurement including at least one of the following measurements: an azimuth, an inclination, and a tool-face direction of the downhole tool string;

aligning an angular orientation of the kickover knuckle joint and the wand with the lateral wellbore as based on the first measurement;

advancing the downhole tool string into the lateral wellbore and obtaining a second measurement with the orientation measurement device while the downhole tool string is positioned in the lateral wellbore, the second measurement including at least one of the azimuth, the inclination, and the tool- face direction of the downhole tool string; and

comparing the second measurement with known deviation survey measurements corresponding to the lateral wellbore and thereby verifying a location of the downhole tool string in the lateral wellbore; and

undertaking one or more wellbore stimulation operations with the downhole tool string while positioned in the lateral wellbore.

2. The method of claim 1, wherein aligning the angular orientation of the kickover knuckle joint and the wand with the lateral wellbore comprises: activating an orienting sub included in the downhole tool string; and changing the angular orientation of the kickover knuckle joint and the wand with the orienting sub.

3. The method of claim 1, wherein the downhole tool string further includes a sequencing flow sub, and wherein undertaking the one or more wellbore stimulation operations comprises:

activating the sequencing flow sub to prevent a stimulation fluid from passing into at least an orienting sub, the kickover knuckle joint, and the wand; and

diverting the stimulation fluid out of the sequencing flow sub.

4. The method of claim 1, wherein undertaking the one or more wellbore stimulation operations comprises at least one of acidizing a portion of the lateral wellbore and hydraulically fracturing a portion of the lateral wellbore.

5. The method of claim 1, wherein the downhole tool string further includes a wellbore telemetry device communicably coupled to the orientation measurement device, the method further comprising communicating the first and second measurements to the surface location in real-time.

6. The method of claim 5, wherein communicating the first and second measurements to the surface location in real-time comprises operating the wellbore isolation device using at least one of mud pulse telemetry, electromagnetic telemetry, acoustic telemetry, ultrasonic telemetry, electrical lines, fiber optic lines, radio frequency transmission, and any combination thereof.

7. The method of claim 1, wherein the downhole tool string further includes a gauge carrier that includes one or more sensors or gauges, the method further comprising measuring one or more downhole parameters with the gauge carrier as the downhole tool string advances within the main or lateral wellbores.

8. The method of claim 1, wherein the lateral wellbore is a first lateral wellbore and the junction is a first junction, the method further comprising :

retracting the downhole tool string from the first lateral wellbore and into the main wellbore;

moving the downhole tool string within the main wellbore toward a second lateral wellbore that extends from the main wellbore at a second junction;

obtaining a third measurement with the orientation measurement device, the first measurement including at least one of the azimuth, the inclination, and the tool-face direction of the downhole tool string;

aligning the angular orientation of the kickover knuckle joint and the wand with the second lateral wellbore as based on the third measurement;

advancing the downhole tool string into the second lateral wellbore and obtaining a fourth measurement with the orientation measurement device while the downhole tool string is positioned in the second lateral wellbore, the fourth measurement including at least one of the azimuth, the inclination, and the tool- face direction of the downhole tool string; comparing the fourth measurement with known deviation survey measurements corresponding to the second lateral wellbore and thereby verifying a location of the downhole tool string in the second lateral wellbore; and

undertaking one or more wellbore stimulation operations with the downhole tool string while positioned in the second lateral wellbore.

9. The method of claim 8, wherein undertaking the one or more wellbore stimulation operations with the downhole tool string while positioned in the second lateral wellbore comprises at least one of acidizing a portion of the second lateral wellbore and hydraulically fracturing a portion of the second lateral wellbore.

10. A rigless well intervention system, comprising :

a downhole tool string extendable within a main wellbore on a conveyance from a surface location, the main wellbore having a central axis and a lateral wellbore that extends from the main wellbore at a junction, wherein at least a portion of each of the main and lateral wellbores is lined with casing, the downhole tool string including :

a wand and a kickover knuckle joint coupled to the wand to deflect the wand from the central axis;

an orienting sub that adjusts an angular orientation of at least the kickover knuckle joint and the wand about the central axis;

an orientation measurement device that measures one or more of an azimuth, an inclination, and a tool-face direction of at least one of the kickover knuckle joint and the wand;

a wellbore telemetry device communicably coupled to the orientation measurement device for communicating at least one of the azimuth, the inclination, and the tool-face direction to the surface location in real-time; and

a sequencing flow sub that is actuatable to prevent a stimulation fluid from passing into at least the orienting sub, the kickover knuckle joint, and the wand, and instead divert the stimulation fluid out of the sequencing flow sub to undertake a wellbore stimulation operation in the lateral wellbore.

11. The system of claim 10, wherein the conveyance is coiled tubing.

12. The system of claim 10, wherein the orienting sub is an indexing tool that rotates a predetermined number of degrees about the central axis upon being activated.

13. The system of claim 10, wherein the orientation measurement device comprises a measurement-while-drilling tool.

14. The system of claim 10, wherein the wellbore telemetry device operates using at least one of mud pulse telemetry, electromagnetic telemetry, acoustic telemetry, ultrasonic telemetry, electrical lines, fiber optic lines, radio frequency transmission, and any combination thereof.

15. The system of claim 10, wherein the stimulation fluid is at least one of a fracturing fluid and an acid.

16. A downhole tool string, comprising :

a wand;

a kickover knuckle joint coupled to the wand to deflect the wand from a central axis;

a wellbore telemetry device communicably coupled to the orientation measurement device for communicating at least one of the azimuth, the inclination, and the tool-face direction to a surface location in real-time; and

a sequencing flow sub that is actuatable to prevent a stimulation fluid from passing into at least the orienting sub, the kickover knuckle joint, and the wand, and instead divert the stimulation fluid out of the sequencing flow sub to undertake a wellbore stimulation operation.

17. The downhole tool string of claim 16, wherein the orienting sub is an indexing tool that rotates a predetermined number of degrees about the central axis upon being activated.

18. The downhole tool string of claim 16, wherein the orientation measurement device comprises a measurement-while-drilling tool.

19. The downhole tool string of claim 16, wherein the wellbore telemetry device operates using at least one of mud pulse telemetry, electromagnetic telemetry, acoustic telemetry, ultrasonic telemetry, an electrical line, a fiber optic line, radio frequency transmission, and any combination thereof.

20. The downhole tool string of claim 16, wherein the stimulation fluid is at least one of a fracturing fluid and an acid.

21. The downhole tool string of claim 16, further comprising :

a motor head assembly; and

a gauge carrier that includes one or more sensors or gauges used to measure downhole parameters.