Methods and electrically-actuated apparatus for wellbore operations

Abstract

Embodiments of a bottomhole assembly BHA for completion of a wellbore are deployed on electrically-enabled coiled tubing (CT) and permit components of the BHA to be independently electrically actuated from surface for completion of multiple zones in a single trip using a single BHA having at least two electrically-actuated variable diameter packers. One or both of the packers may be actuated to expand or retract for opening and closing off a variety of flowpaths between the BHA and the wellbore, in new wellbores, old wellbores, cased wellbores, wellbores with sleeves and in openhole wellbores. Additional components in the BHA, which may also be electrically-actuated or powered, permit perforating, locating of the BHA in the wellbore such as using casing collar locators and microseismic monitoring in real time or in memory mode.

The embodiments in which an exclusive property or privilege is claimed are defined as follows: 
     
         1 . A system for completing and treating a wellbore, the system comprising:
 electrically-enabled coiled tubing (CT) having a CT bore formed therethrough; and   a bottom hole assembly (BHA) having, from a proximal end to a distal end, at least a treatment head and a packer, wherein   the treatment head comprises fracturing ports to an annulus between the BHA and wellbore;   the packer being electrically-actuated and comprising
 a packer element; and 
 an electric packer drive electrically connected to the CT for electrically actuating the packer element between a first sealing diameter for sealing in the wellbore and at least a second running diameter, the running diameter being sized to be movable within the wellbore and acting as a piston for pumping the BHA and CT downhole within the wellbore. 
   
     
     
         2 . The system of  claim 1 , wherein the packer further comprises slips. 
     
     
         3 . The system of  claim 1  wherein the CT and BHA form an injection string, the system further comprising:
 a strain sensor along the injection string uphole of the packer, the strain sensor electrically connected to the CT for providing signals indicative of axial loading in the string at about BHA, 
 a controller for receiving axial loading signals and for managing a rate of injection of the CT and a rate of pumping of the BHA for managing the axial loading. 
 
     
     
         4 . The system of  claim 1  wherein the wellbore is cased or lined, further comprising:
 a casing collar locater (CCL) for engaging a casing collar for positioning the BHA in the wellbore; and 
 a perforating apparatus for perforating the casing or liner. 
 
     
     
         5 . The system of  claim 2  wherein the perforating apparatus is an electrically-actuated, selectively-fired perforating gun further comprising a plurality of perforating segments, the system further comprising:
 a top connector sub at the perforating apparatus for selectively triggering each of the perforating segments; and 
 a firing panel at surface, the firing panel being electrically connected to the CT and to the top connector sub. 
 
     
     
         6 . The system of  claim 1 , wherein the BHA comprises a throughbore and the treatment head further comprises a valve for alternately directing fluid to either the fracturing ports or the throughbore, the valve being electrically actuated, the BHA further comprising an electric valve drive electrically connected to the CT for actuating the valve. 
     
     
         7 . The system of  claim 6  wherein the valve further directs fluid from the throughbore to a bore of the BHA below the packer. 
     
     
         8 . The system of  claim 1  wherein the electric drive further actuates the packer to a minimum packer diameter for tripping out of the wellbore. 
     
     
         9 . The system of  claim 2  wherein the CCL is electronic and electrically connected to the CT through an electronics sub in the BHA. 
     
     
         10 . The system of  claim 1  wherein the BHA further comprises:
 one or more seismic sensors for monitoring microseismic signals during fracturing. 
 
     
     
         11 . The system of  claim 10  wherein the one or more sensors are two or more axially spaced, 3-component geophones. 
     
     
         12 . The system of  claim 10  wherein the one or more seismic sensors are positioned downhole of the treatment head for isolating the one or more sensors therefrom. 
     
     
         13 . The system of  claim 10  further comprising sensors for determining orientation of the one or more seismic sensors relative to surface. 
     
     
         14 . The system of  claim 10  wherein microseismic data from the one or more seismic sensors are electrically connected to the CT for communication of microseismic data to surface in real time. 
     
     
         15 . The system of  claim 10  further comprising a downhole processor with memory for storing microseismic data from the one or more seismic sensors for retrieval therefrom at surface. 
     
     
         16 . The system of  claim 1  wherein the CT further comprises fiber optics extending uphole from the BHA for optical signal communication between the BHA and surface. 
     
     
         17 . The system of  claim 10  wherein the CT further comprises fiber optics extending uphole from the BHA, the fiber optics forming a linear array of distributed fiber optic sensors for along the wellbore for detecting compressional waves from background noise and transmitting the signals therefrom to surface, for removal of the noise from the microseismic signals. 
     
     
         18 . The system of  claim 10  wherein the two or more axially spaced, 3-component geophones further comprise arms electrically connected to the CT and actuable between
 an extended position for coupling the geophones to the casing or wellbore for seismic coupling thereto; and 
 a retracted position for decoupling therefrom. 
 
     
     
         19 . The system of  claim 1  wherein the BHA further comprises:
 an electronics sub; and 
 pressure sensors electrically connected to the electronics sub for monitoring pressure above and below the at least one packer, 
 the electronics sub electrically connected to the CT for communications to surface. 
 
     
     
         20 . The system of  claim 19  wherein the BHA further comprises:
 temperature and vibration sensors electrically connected to the electronics sub. 
 
     
     
         21 . The system of  claim 1  wherein the packer is a first packer and the electric drive is a first electric drive, the system further comprising:
 a second packer, uphole of the treatment head, the second packer having a packer element and being electrically-actuated; and 
 a second electric packer drive electrically connected to the CT for electrically actuating the second packer element between the sealing position and at least a second running diameter, the running diameter of the second packer element being sized to be movable within the wellbore and acting as a piston for pumping the BHA and CT downhole within the wellbore. 
 
     
     
         22 . The system of  claim 21  wherein:
 the first packer element is electrically-actuated to a minimum diameter; and 
 the second packer element is electrically-actuated for pumping the BHA and CT downhole within the wellbore. 
 
     
     
         23 . The system of  claim 21 , wherein the BHA is secured in the wellbore as a result of pressure balancing across the first and second packers. 
     
     
         24 . The system of  claim 21  wherein the BHA further comprises:
 an electronics sub; and 
 pressure sensors electrically connected to the electronics sub for monitoring pressure above and below each of the first and second packers. 
 
     
     
         25 . The system of  claim 21 , wherein the BHA comprises a throughbore and the treatment head further comprises a valve for alternately directing fluid to either the fracturing ports or the throughbore, the valve being electrically actuated, the BHA further comprising an electric valve drive electrically connected to the CT for actuating the valve. 
     
     
         26 . The system of  claim 25  wherein the valve further directs fluid from the throughbore to a bore of the BHA below the packer. 
     
     
         27 . The system of  claim 21  wherein the BHA further comprises:
 one or more seismic sensors for monitoring microseismic signals during fracturing. 
 
     
     
         28 . The system of  claim 27  wherein the one or more sensors are two or more axially spaced, 3-component geophones. 
     
     
         29 . The system of  claim 27  wherein the one or more seismic sensors are positioned downhole of the treatment head for isolating the one or more sensors therefrom. 
     
     
         30 . The system of  claim 27  further comprising sensors for determining orientation of the one or more seismic sensors relative to surface. 
     
     
         31 . The system of  claim 27  wherein microseismic data from the one or more seismic sensors are electrically connected to the CT for communication of microseismic data to surface in real time. 
     
     
         32 . The system of  claim 27  further comprising a downhole processor with memory for storing microseismic data from the one or more seismic sensors for retrieval therefrom at surface. 
     
     
         33 . The system of  claim 21  wherein the CT further comprises fiber optics extending uphole from the BHA for optical signal communication between the BHA and surface. 
     
     
         34 . The system of  claim 27  wherein the CT further comprises fiber optics extending uphole from the BHA, the fiber optics forming a linear array of distributed fiber optic sensors for along the wellbore for detecting compressional waves from background noise and transmitting the signals therefrom to surface, for removal of the noise from the microseismic signals. 
     
     
         35 . The system of  claim 21  wherein the wellbore is cased or lined and having fluid communication with the wellbore, further comprising a casing collar locater (CCL) for engaging a casing collar for positioning the BHA in the wellbore. 
     
     
         36 . The system of  claim 35  further comprising perforating apparatus for perforating the casing or liner. 
     
     
         37 . The system of  claim 36  wherein the perforating apparatus is an electrically-actuated, selectively-fired perforating gun further comprising a plurality of perforating segments, the system further comprising:
 a top connector sub at the perforating apparatus for selectively triggering each of the perforating segments; and 
 a firing panel at surface, the firing panel being electrically connected to the CT and to the top connector sub. 
 
     
     
         38 . A method of deploying and positioning a BHA in a wellbore comprising:
 deploying the BHA in electrically-enabled coiled tubing, the BHA comprising at least one packer having an electrically-actuable packer element   electrically actuating the packer element to expand to a running diameter being less than a diameter of the wellbore;   pumping fluid through an annulus between the wellbore and the BHA, the packer element acting as a hydraulic piston for pumping the packer, the BHA and the CT downhole in the wellbore; and   electrically actuating the packer element to expand to a sealing diameter for sealing the annulus.   
     
     
         39 . The method of  claim 38  wherein the step of deploying the BHA, when encountering debris in the wellbore, further comprises:
 electrically actuating the packer element to reduce to a minimum diameter less than the running diameter, to permit the debris to pass the packer and BHA. 
 
     
     
         40 . A method for treating one or more zones of interest in a formation intersected by a cased wellbore comprising:
 providing a bottom-hole assembly (BHA) and electrically-enabled coiled tubing (CT), the CT having a CT bore therethrough, the BHA having, from a proximal end to a distal end, at least a treatment head, at least one packer and a perforating apparatus,   preparing BHA packer for running into the wellbore by electrically actuating a packer element to a running diameter   pumping fluid through an annulus between the BHA and the casing to act at the packer for pumping the BHA and CT downhole and positioning the perforation apparatus adjacent a lowermost zone of interest;   actuating the perforating apparatus to perforate the casing at the zone of interest;   pumping fluid through the annulus for pumping the BHA and CT downhole so as to position the packer below the perforations;   electrically-actuating the packer element to a sealing position to seal the annulus and anchor the BHA in the cased wellbore;   pumping a treatment fluid through the annulus, through the coiled tubing and through the treatment head, or both, for delivery to the perforations and the zone of interest;   stopping the pumping of the treatment fluid;   equalizing pressure across the packer;   electrically-actuating the packer element from the sealing diameter to the running diameter;   pulling the CT and BHA uphole for repositioning the perforating apparatus adjacent another uphole zone of interest; and   without removing the BHA from the wellbore, repeating the steps for the at least the another uphole zone of interest.   
     
     
         41 . The method of  claim 40  wherein the pumping of the treatment fluid through the annulus, or through the CT for pumping through the treatment head, or both, further comprises electrically actuating a valve at the treatment head for alternately directing fluid from the CT bore to the annulus. 
     
     
         42 . The method of  claim 40  wherein the perforating apparatus is an electrically-actuated perforating gun comprising a plurality of perforating segments electrically connected to the CT and to a firing panel at surface, the step of actuating the perforating apparatus comprises:
 electronically actuating, from the firing panel, a select one or more of the perforating segments. 
 
     
     
         43 . The method of  claim 40  wherein the BHA further comprises a casing collar locator (CCL), the step of positioning the BHA further comprising:
 engaging the CCL with a casing collar adjacent the zone of interest for positioning the BHA. 
 
     
     
         44 . The method of  claim 43  wherein the casing collar locator (CCL) is electrically connected to the CT, the step of positioning the further comprises:
 electrically sensing a casing collar or perforations in the wellbore at the zone of interest with the CCL for positioning the BHA. 
 
     
     
         45 . The method of  claim 40  wherein the BHA further comprises pressure sensors electrically connected to the CT above and below the packer; and after the step of electrically actuating the packer element to reduce from the sealing diameter to the running diameter for relocating the BHA in the wellbore or tripping the BHA out of the wellbore, the method further comprising:
 monitoring the pressure data from the one or more pressure sensors at surface for determining when the pressure above the packer and below the packer are balanced. 
 
     
     
         46 . The method of  claim 40  wherein the cased wellbore has a plurality of spaced apart ported sleeve subs incorporated therein, sleeves in the ported sleeve subs being actuable between a closed position for blocking one or more ports through the casing and an open position for opening the one or more ports for treating the formation therethrough, the method comprising:
 engaging the sleeve at the zone of interest with the BHA and electrically-actuating the BHA to move the sleeve to the open position. 
 
     
     
         47 . The method of  claim 46 , after the step of pumping the treatment fluid to the perforations, further comprises:
 engaging the sleeve with the BHA and electrically-actuating the BHA to move the sleeve to the closed position.   
     
     
         48 . The method of  claim 40 , wherein the BHA further comprises one or more 3-component sensors, the method comprising:
 monitoring microseismic events in the wellbore and outside the wellbore using the one or more 3-component sensors for collecting microseismic data from x, y and z.   
     
     
         49 . The method of  claim 48  wherein the one or more 3-component sensors are electrically connected to the CT, the method comprising:
 transmitting the x, y and z data from the two or more 3-component sensors to surface through the electrically-enabled CT, in real time. 
 
     
     
         50 . The method of  claim 48 , wherein one or more 3-component sensors comprise storage memory and a battery, the method further comprising:
 storing the x, y and z data from the two or more 3-component sensors in the memory   retrieving the storage memory to surface with the BHA.   
     
     
         51 . The method of  claim 40  wherein the packer is a downhole first packer and the BHA further comprises an uphole second packer having a packer element independently controllable from the first packer, the second packer being spaced uphole of the fracturing ports and electrically connected to the CT; the step of deploying the BHA further comprising:
 electrically actuating the packer element of one or both of the first and second packers to expand the diameter to the running diameter; 
 pumping fluid through the annulus for pumping the one or both of the first and second packers and the BHA downhole; and 
 prior to pumping treatment fluid through the annulus, 
 actuating the packer element of the second packer to retract to a minimum packer diameter. 
 
     
     
         52 . The method of  claim 51  wherein one or more perforations has sanded-off, the method further comprising:
 releasing the second packer by electrically actuating the packer elements of the second packer to reduce the diameter to about a minimum disameter; 
 pumping a fluid through the CT bore for circulating the fluid to surface through the annulus for cleaning sand from the perforations; and when cleaned 
 electrically-actuating the second packer to re-expand the packer element to the sealing diameter for re-sealing the annulus between the BHA and the wellbore uphole of the perforations; and 
 pumping the treatment fluid to the perforations and into the formation. 
 
     
     
         53 . The method of  claim 40  for use in wellbores having existing perforations or open ports therein, wherein the packer is a first packer and the BHA further comprises a second packer having a packer element independently controllable from the first packer, the second packer being positioned uphole of the fracturing ports, further comprising:
 positioning the BHA having the second packer uphole of the existing perforations or open ports and the first packer downhole thereof; 
 independently electrically-actuating the packer element of each of the first packer and the second packer to the sealing diameter for sealing the annulus between the BHA and the wellbore above and below the existing perforations; 
 pumping the treatment fluid through the CT bore to the fracturing ports for delivery to the zone of interest; 
 stopping the pumping of the treatment fluid; and 
 independently electrically-actuating the packer element of the first packer and the packer element of the second packer to reduce the diameter to the running diameter. 
 
     
     
         54 . A method for treating multiple intervals of one or more formations intersected by a cased wellbore having existing perforations or open ports therein, at one or more zones of interest, the method comprising:
 injecting a bottom-hole assembly (BHA) into the wellbore using electrically-enabled coiled tubing (CT), the CT having a CT bore therethrough, the BHA having, from a proximal end to a distal end, at least a treatment head, a first packer downhole of the treatment head and a second packer uphole of the treatment head wherein
 the treatment head comprises fracturing ports, a throughbore and a valve for alternately directing fluid between the fracturing ports and the throughbore; and 
 each of the first and second packers comprises a packer element and an electric packer drive electrically connected to the coiled tubing for independently actuating the packer element of the first and second packer between a sealing diameter for sealing in the wellbore and a running diameter for acting as a piston to aid in moving the BHA and CT downhole within the wellbore. 
   electrically-actuating the packer element of one or both of the first and second packers to the running position;   pumping fluid through an annulus between the BHA and the casing to act at the packer in the running diameter for positioning the BHA having the first packer below the existing perforations or open ports and the second packer thereabove for straddling the perforations or open ports;   electrically-actuating the packer element of the first packer and the second packer to the sealing position to seal in the wellbore;   anchoring the BHA in the cased wellbore;   pumping a treatment fluid through the CT bore to the fracturing ports for delivery to the perforations or open ports and to the zone of interest;   stopping the pumping of the treatment fluid;   equalizing pressures above, between and below the first and second packers;   electrically actuating the packer elements of the first and second packer element to reduce from the sealing diameter to at least the running diameter;   repositioning the BHA so as to straddle existing perforations or open ports between the first and second packers at another zone of interest; and   without removing the BHA from the wellbore, repeating the steps for the at least the another zone of interest.   
     
     
         55 . The method of  claim 54  wherein the wellbore further comprises one or more zones of interest without existing perforations or opened ports therein, the BHA further comprising a perforating apparatus downhole of the first packer, the method further comprising:
 positioning the BHA having the perforating apparatus adjacent one of the one or more zones without existing perforations or opened ports; 
 actuating the perforating apparatus to form new perforations at the zone of interest without existing perforations; 
 repositioning the BHA having the first packer downhole of the new perforations and the second packer thereabove; 
 independently electrically-actuating the packer element of the first and second packer to expand to the sealing diameter for sealing the annulus between the BHA and the wellbore; 
 pumping the treatment fluid through through the CT bore to the fracturing ports for delivery to the perforations and to the formation therethrough; 
 stopping the pumping of treatment fluid; 
 equalizing pressures above, between and below the first and second packers; 
 independently electrically actuating the packer element of each of the first and second variable diameter packers to reduce to at least the running diameter; and 
 repositioning the BHA adjacent another zone of interest without removing the BHA from the wellbore. 
 
     
     
         56 . The method of  claim 54  wherein the perforating apparatus is an electrically-actuated perforating gun comprising a plurality of perforating segments electrically connected to the CT and to a firing panel at surface, the step of actuating the perforating apparatus comprises:
 electronically actuating, from the firing panel, a select one or more of the perforating segments. 
 
     
     
         57 . A method for treating multiple intervals of one or more formations intersected by a cased wellbore in a single trip wherein one or more perforations has sanded-off, the method comprising:
 injecting a bottom-hole assembly (BHA) into the wellbore using electrically-enabled coiled tubing (CT), the CT having a CT bore therethrough, the BHA having, from a proximal end to a distal end, at least a treatment head, a first packer downhole of the treatment head and a second packer uphole of the treatment head wherein
 the treatment head comprises fracturing ports, a throughbore and a valve for alternately directing fluid between the fracturing ports and the throughbore; and 
 the first and second packers comprises a packer element and an electric packer drive electrically connected to the coiled tubing for independently actuating the packer element of the first and second packer between a sealing diameter for sealing in the wellbore and a running diameter for acting as a piston to aid in moving the BHA and CT downhole within the wellbore. 
   positioning the BHA having the second packer uphole of perforations or open ports at a first zone of interest and the first variable diameter packer downhole thereof;   electrically-actuating packer elements of the second packer to expand the variable diameter to a sealing diameter for sealing an annulus between the BHA and the wellbore;   electrically-actuating packer elements of the second packer to expand the variable diameter to a sealing diameter for sealing an annulus between the BHA and the wellbore therebelow;   pumping a treatment fluid to the perforations and into the formation, through the coiled tubing to the fracturing ports and to the perforations or opened ports; and   wherein when the perforations or open ports sands off
 releasing the second variable diameter packer by electrically actuating the packer elements of the second packer to reduce the diameter of the second packer to a minimum packer diameter; 
 continuing pumping a fluid for circulating the fluid to surface through the annulus for cleaning sand from the perforations for clearing the sand-off and thereafter 
 electrically-actuating the second packer to re-expand the packer elements to the sealing diameter for re-sealing the annulus between the BHA and the wellbore uphole of the perforations; and 
 pumping the treatment fluid to the perforations and into the formation, through the coiled tubing to the fracturing ports and to the perforations or opened ports. 
   
     
     
         58 . A method for reducing rock stress during treatment of a formation comprising:
 deploying a BHA in a wellbore;   positioning fracturing ports in the BHA adjacent a first zone of interest;   setting a packer in the BHA below the fracturing ports to isolate an annulus between the BHA and the wellbore;   delivering treatment fluid to the fracturing ports for fracturing the formation at the zone of interest;   releasing the packer;   repositioning the BHA for positioning fracturing ports in the BHA at a subsequent zone of interest adjacent the first zone of interest;   setting the packer to isolate the annulus; and   while delivering treatment fluid to the fracturing ports for fracturing the formation at the subsequent adjacent zone of interest;   flowing fluid through the BHA to below the packer for delivery to the first zone of interest for reducing rock stress in the first zone of interest during fracturing of the adjacent zone of interest.   
     
     
         59 . The method of  claim 58  further comprising:
 repeating the steps of repositioning, setting and flowing fluid below the packer to the zones therebelow while delivering treatment fluid to another subsequent zones of interest. 
 
     
     
         60 . A method for reducing rock stress during treatment of a formation comprising:
 injecting a bottom-hole assembly (BHA) into the wellbore using electrically-enabled coiled tubing (CT), the CT having a CT bore therethrough, the BHA having, the BHA having, from a proximal end to a distal end,
 at least a treatment head and a packer, wherein 
 the treatment head comprises fracturing ports, a throughbore and a valve for alternately directing fluid between the fracturing ports and the throughbore; and 
 the packer comprises a packer element and an electric packer drive electrically connected to the coiled tubing for actuating the packer element between a sealing diameter for sealing in the wellbore and a running diameter for acting as a piston to aid in moving the BHA and CT downhole within the wellbore; 
   electrically-actuating the packer element to the running position;   pumping fluid through an annulus between the BHA and the casing to act at the packer for positioning the BHA so as to position the packer below perforations in the wellbore;   electrically-actuating the packer element to the sealing position to seal in the wellbore;   pumping a treatment fluid through the annulus, through the CT, or both, for delivery to the perforations and the zone of interest;   stopping the pumping of the treatment fluid;   electrically actuating the packer element to reduce from the sealing diameter to the running diameter;   repositioning the BHA at a subsequent adjacent zone of interest; and   while delivering treatment fluid to the fracturing ports for fracturing the formation at the subsequent adjacent zone of interest;   actuating the valve for delivery fluid to the fracturing ports and to the throughbore for delivering fluid below the packer; and   flowing fluid below the packer for delivery to the first zone of interest for reducing rock stress in the first zone of interest during fracturing of the subsequent adjacent zone of interest.   
     
     
         61 . The method of  claim 60  further comprising:
 repeating the steps of repositioning, setting and flowing fluid below the packer to the zones therebelow while delivering treatment fluid to another subsequent zones of interest.