Multilateral access with real-time data transmission

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.

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;   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.   
     
     
         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.