Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B47/00—Survey of boreholes or wells
  • E21B47/09—Locating or determining the position of objects in boreholes or wells, e.g. the position of an extending arm; Identifying the free or blocked portions of pipes

Definitions

• This invention relates generally to tools conveyed into a wellbore while forming the wellbore. More specifically, the invention relates to methods and apparatus for determining a position or speed of a tool conveyed into a drill string while a downhole apparatus is downhole to form the wellbore.
• Wellbores for use in subterranean extraction of hydrocarbons generally comprise a main wellbore section running in a substantially vertical direction along its length. Lateral wellbores may be formed from the main wellbore into the subterranean rock formation surrounding the main wellbore.
• the lateral wellbores are usually formed to enhance the hydrocarbon production of the main wellbore and can be formed after formation of the main wellbore. Alternatively, the lateral wellbores can be made after the main wellbore has been in production for some time.
• the lateral wellbores may have a smaller diameter than that of the main wellbores and are often formed in a substantially horizontal direction.
• an apparatus for conveying a tool while drilling a wellbore includes a line coupled to the tool, a conveying assembly coupled to the line, the conveying assembly located at a surface and configured to release the line to convey the tool into the drill string and a sub including a passage for the line to pass therethrough.
• the apparatus also includes a measuring device configured to determine a position of the tool within the drill string by determining a length of the line that is conveyed along with the tool into the drill string.
• a method for conveying a tool into a drill string includes forming a wellbore with a bottomhole assembly and conveying the tool into the drill string, the tool being coupled to one end of a line coupled to an assembly at a surface, wherein conveying includes allowing the tool to free fall to a first location in the drill string.
• the method also includes pumping the tool from the first location to a second location in the drill string and determining a position of the tool within the drill string by measuring a length of the line that is conveyed along with the tool into the drill string.
• FIG. 1 shows a schematic diagram of an embodiment of a drilling system with a tool conveyed uphole of a BHA inside a tubular;
• FIG. 2 is a schematic diagram of an embodiment of a tool being conveyed into a drill string.
• FIG. 1 is a schematic diagram of an exemplary drilling system 100.
• the diagram shows a wellbore 110 that includes an upper section 111 with a casing 112 installed therein and a lower section 114 being drilled with a drill string 1 18.
• the drill string 118 includes a tubular member 116 carrying borehole assembly (or "BHA") 130 at its bottom end.
• the tubular member 116 may be formed by joining drill pipe sections or it may be composed of a coiled-tubing.
• a drill bit 150 is attached to the bottom end of the BHA 130 to disintegrate rocks in the earth formation to drill the wellbore 110.
• the drill string 118 is shown conveyed into the wellbore 110 from a rig 180 at the surface 167.
• the rig 180 shown is a land rig for ease of explanation.
• the apparatus and methods disclosed herein may also be utilized when an offshore rig (not shown) is used.
• a rotary table 169 or a top drive (not shown) coupled to the drill string 118 may be utilized to rotate the drill string 118 at the surface, which rotates the BHA and thus the drill bit 150 to drill the wellbore 110.
• a drilling motor 155 also referred to as "mud motor" in the BHA 130 may be utilized alone to rotate the drill bit 150 or to superimpose upon the drill bit rotation by the rotary table 169.
• a Rotary Steerable System or conventional rotary assembly is used to rotate drill bit 150.
• a control unit (or “controller”) 190 which is a computer-based unit, is placed at the surface for receiving and processing data transmitted by the sensors in the drill bit and BHA 130 and for controlling selected operations of the various devices and sensors in the BHA 130.
• the surface controller 190 includes a processor 192, a data storage device (or “computer-readable medium”) 194 for storing data and computer programs 196.
• the data storage device 194 is any suitable device, including, but not limited to, a read-only memory (ROM), random-access memory (RAM), flash memory, magnetic tape, hard disk and an optical disk.
• a drilling fluid from a source thereof 179 is pumped under pressure through the tubular member 116, which fluid discharges at the bottom of the drill bit 150 and returns to the surface via the annular space 127 (also referred as the "annulus") between the drill string 118 and the inside wall of the wellbore 110.
• the drill bit 150 in one embodiment, includes sensors 160 and 162, circuitry for processing signals from such sensors and for estimating one or more parameters relating to the drill bit 150 or drill string during drilling of the wellbore 110.
• the BHA 130 further includes one or more downhole sensors (also referred to as the MWD or LWD sensors), collectively designated herein by numeral 175, and at least one control unit (or controller) 170 for processing data received from the MWD sensors 175, sensors 160 and 162, and other sensors in the BHA 130.
• the controller 170 includes a processor 172, such as a microprocessor, a data storage device 174 and programs 176 for use by the processor 172 to process downhole data and to communicate with the surface controller 190 via a two-way telemetry unit 188.
• a processor 172 such as a microprocessor
• a data storage device 174 and programs 176 for use by the processor 172 to process downhole data and to communicate with the surface controller 190 via a two-way telemetry unit 188.
• the exemplary drilling system 100 further includes a conveying apparatus 140 configured to convey a tool 141 within tubular 116.
• the conveying apparatus 140 includes a line 142, conveying assembly 143 and sub 144.
• the conveying apparatus 140 conveys the tool 141 downhole via line 142 that is released and controlled by conveying assembly 143.
• the line 142 is any suitable high strength line coupled to the tool 141 and conveying assembly 143.
• Non- limiting examples of line 142 include a wire, a fiber and a cable, wherein the line 142 comprises a suitable material such as a metal, metal alloy, plastic or other durable material.
• the line 142 is a mechanical conveyance device, wherein the line 142 does not provide any communication or signals between the tool 141 and surface 167.
• the tool 141 is an independently operating tool, such as a self powered measurement system with on-board power, sensors, processors and memory to enable selected downhole parameters to be recorded.
• an exemplary tool 141 includes a logging instrument, battery and controller for the logging instrument.
• the instrument includes sensors used for making formation evaluation (FE) measurements.
• the tool 141 includes structures, such as swab cups to enable the tool 141 to be pumped along the drill string 118.
• the end of the exemplary tool 141 is provided with a structure, such as a collet catcher, configured to engage a stop on the BHA 130.
• the drill string 118 needs no modifications to make FE measurements with tool 141.
• Other FE measurement tools or devices use a special sub on the drill string 118 or use slots on the drill string 118 for making the FE measurements.
• Other embodiments of conveying apparatus 140 may not include sub 144.
• the conveying assembly 143 includes a suitable mechanical, electrical and/or hydraulic device to facilitate a controlled release of line 142.
• the conveying assembly 143 further includes a measuring device 145 configured to determine a length of line 142 released to convey the tool 141 downhole.
• the measuring device 145 provides accurate position and speed measurements relating to tool 141 as it travels downhole.
• the conveying apparatus 140 conveys the tool 141 after the BHA 130 has stopped drilling or forming the wellbore 110.
• the tool 141 is released into the drill string 118 wherein gravity causes the tool to free fall to a selected position in the well, such as first position 147, where the tool 141 stops.
• the weight of the tool 141 and gravitational force cause the free fall of the tool
• first position 147 frictional forces are increased due to wellbore 110 deviation, increased drilling mud density and/or flow of drilling mud or other forces.
• drilling mud is pumped from source 179 downhole to further drive the tool 141 from the first position 147 to a second position 148, thereby overcoming the frictional forces.
• second position 148 is proximate a top portion of BHA 130.
• FIG. 2 is a schematic diagram of an embodiment of a conveying apparatus 200.
• the conveying apparatus 200 includes a conveying assembly 202, controller 204, measurement device 206 and sub 212.
• the conveying apparatus 200 and measurement device 206 are configured to determine one or more parameters relating to the position and speed of the tool 141 in the drill string 118 at a selected time.
• the conveying assembly 202 includes a spool 208 and motor 210 configured to release the line 142 which is coupled to tool 141. As depicted, the line
• the tool 141 passes through an opening in sub 212 into drill string 118.
• the tool 141 free falls 214 from the surface 167 to first position 147 due to gravitational force.
• the drilling mud source 179 pumps mud into the drill string 118 to push tool 141 to second position 148, as indicated by arrow 216.
• the tool 141 is conveyed into drill string 118 toward BHA 130, which is located proximate an end of the wellbore 110.
• the conveying apparatus 200 determines a position and speed of the tool 141 as it moves within the drill string 118.
• the measurement device 206 determines the amount of wire 142 that passes from the conveying apparatus to 200 determine the speed and position or depth of the tool 141 in the drill string 118. This determination is made because the position of the conveying apparatus 200 relative to the wellbore is known and fixed. Thus, the amount of line 142 that passes from the conveying apparatus 200 corresponds to the position or depth of tool 141 within the drill string 118.
• the measuring device 206 is configured to determine the speed of the tool 141 as it travels through the drill string 118 by measuring the rate at which line 142 passes from conveying assembly 202.
• the measuring device 206 provides position data for the tool 141 to correspond with measurements taken downhole, such as FE measurements. Further, the measuring device 206 determines the position of tool 141 to enable the controller 204 to determine when to pump drilling mud from source 179 to convey 216 the tool 141 to the second position 148. The speed measurement determined by measuring device 206 can also be used as feedback for controller 204 as it controls the motor 210 and release of line 142.
• the sub 212 is any suitable sub that is located at the surface 167 and coupled to an upper portion of drill string 118. The sub 212 includes a passage for line 142 to pass through as the tool 141 is conveyed within drill string 118. An exemplary sub 212 is substantially sealed to an upper portion of drill string 118 to enable the pumping of drilling mud from source 179 through drill string 118 to convey the tool 141 towards BHA 130.

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• Physics & Mathematics (AREA)
• Life Sciences & Earth Sciences (AREA)
• Engineering & Computer Science (AREA)
• Geology (AREA)
• Mining & Mineral Resources (AREA)
• Geophysics (AREA)
• Environmental & Geological Engineering (AREA)
• Fluid Mechanics (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Geochemistry & Mineralogy (AREA)
• Earth Drilling (AREA)

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• 2011
  • 2011-10-20 US US13/277,769 patent/US20120097452A1/en not_active Abandoned
  • 2011-10-26 CA CA2816074A patent/CA2816074A1/en not_active Abandoned
  • 2011-10-26 EP EP11837007.1A patent/EP2633157A2/de not_active Withdrawn
  • 2011-10-26 WO PCT/US2011/057867 patent/WO2012058296A2/en not_active Ceased

Non-Patent Citations (1)

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