Stabilizer Assembly
In one aspect of the present invention, a stabilizer assembly on a downhole tool string component, comprising a sleeve slideably attached to a mandrel of the tool string component. At least one stabilizer blade is formed in the sleeve and generally follows the length of the sleeve. A gap is formed in the at least one blade separating a first and second portion of the blade.
The present invention relates to stabilizer assemblies, specifically stabilizer assemblies for use in oil, gas and geothermal drilling. Stabilizer assemblies are placed on a downhole tool string component to centralize the drill string in the bore hole.
U.S. Pat. No. 4,685,895 to Hatten which is herein incorporated by reference for all that it contains, discloses a stabilizer mechanism for guiding drill direction of a flexible drill string when drilling the straight portion of a deviated well bore. The stabilizing mechanism comprises a tubular mandrel adapted for connection between the flexible drill string and a drill bit. The mandrel has at least two, reduced diameter areas spaced apart and disposed axially along its length. A non-rotating type stabilizer sleeve is positioned on each of the reduced diameter areas. Bearing means is provided at each end of each of the sleeves to reduce wear. The mandrel is capable of traversing a short radius curve of a deviated well.
U.S. Pat. No. 6,564,883 to Fredericks et al. which is herein incorporated by reference for all that it contains, discloses a logging-while-drilling method and apparatus for obtaining information about a formation uses a plurality of rib sets with pad-mounted sensor on one or more selectively non-rotating sleeves attached to a rotating housing that is part of a drilling assembly. The sensors may be density, neutron, NMR, resistivity, sonic, dielectric or any number of other sensors. In an alternative arrangement, the sensors rotate with the drill string.
U.S. Pat. No. 5,250,806 to Rhein-Knudsen et al. which is herein incorporated by reference for all that it contains, discloses an apparatus and method for measuring density, porosity and other formation characteristics while drilling. The apparatus, preferably housed in a drill collar and placed within a drill string, includes a source of neutrons and a source of gamma rays placed within a tubular body which is adapted to provide for the flow drilling through it. Two sets of stabilizer blades are provided. One set, associated with the neutron source, includes secondary radiation detectors that are placed radially beyond the nominal outer radius of the body. Formation porosity measurement accuracy is substantially enhanced since the standoff of the detectors from the formation is substantially decreased. Another set, associated with the gamma ray source, includes one or more gamma ray detection assemblies in a single blade. Each of the gamma ray detector assemblies is also placed radially beyond the nominal outer radius of the tubular wall.
U.S. Pat. No. 6,622,803 to Harvey et al. which is herein incorporated by reference for all that it contains, discloses a stabilizer especially adapted for use with a drill string having an eccentric drilling element, such as a bi-center bit. The stabilizer has a pair of circumferentially displaced blades that lie in a common circumferential plane and extend from a rotatable sleeve supported on the stabilizer body, as well as a stationary blade. The rotating blades are aligned with the stationary blade when in a first circumferential orientation are disposed so that the mid-point between the rotating blades is located opposite the stationary blade, thereby providing full gauge stabilization, when the rotating blades are in a second circumferential orientation. A magnetic system senses the circumferential orientation of the rotating blades and transmits the information to the surface via mud pulse telemetry. A piston actuated by the drilling mud locks the rotating blades into the active and inactive positions. A brake shoe located on the distal end of each rotating blade provides contact with the walls of the bore hole and serves as a support pad for a formation sensor.
BRIEF SUMMARY OF THE INVENTIONIn one aspect of the present invention, a stabilizer assembly on a downhole tool string component, comprising a sleeve slideably attached to a mandrel of the tool string component. At least one stabilizer blade is formed in the sleeve and generally follows the length of the sleeve. A gap is formed in the at least one blade separating a first and second portion of the blade.
The gap may be 3.5 feet long and may be at least one foot long. The length of the gap may be at least twice the width of the blade. The first and second portion of the blade may be offset. The first or second portion may be less than 5 feet long. The gaps may add compliance to the stabilizer.
A plurality of gaps may be formed in the at least one blade. The plurality of gaps may be offset one from another. The plurality of gaps may be the same size. The plurality of gaps may be force or mass balanced with respect to the rotation of the downhole tool string. The stabilizer may be in gauge, near gauge, or under gauge with respect to the bit gauge. The stabilizer blades may be replaceable to change the gauge or the compliancy of the stabilizer depending on the application or replace it after significant wear.
At least one instrumentation device may be disposed in the at least one blade to gather subterranean data. The at least one instrumentation device may comprise at least one signal source. The signal source may be a seismic source, a sonic source, an explosive, a compressed air gun, a vibrator, a sparker, an electromagnetic device, a density source, a pulse neutron generator or combinations thereof.
The at least one instrumentation device may comprise at least one sensor. The at least one sensor may be selected from the group consisting of accelerometers, inclinometers, pressure transducers, magnetometers, gyroscopes, temperature sensors, gamma ray sensors, neutron sensors, seismic sensors, sonic sensors, mud logging devices, resistivity sensors, induction sensors, nuclear sensors, imaging devices, GPS devices, Hall-effect sensors, permeability sensors, porosity sensors, vibration sensors, electrical potential sensors, geophones or combinations thereof.
The at least one instrumentation device may be powered by a turbine, a battery, or a power transmission system from the surface or downhole. The at least one instrumentation device may be in communication with a downhole telemetry system. The at least one instrumentation device may be passively decoupled from the stabilizer assembly. The at least one instrumentation device may be actively decoupled from the stabilizer assembly.
At least one pocket may be formed on an inner diameter of the sleeve. The sleeve may be segmented. A contour of the blade at an end of the blade may have a biased curvature to accommodate mud flow. The segmented sleeve may be joined mechanically. The segmented sleeve may be joined through a castle connection. The segmented sleeve may allow for lengthening or shortening of the stabilizer assembly. In embodiments where the stabilizer assembly accommodates formation instrumentation, more or less instrumentation may be added or to modifidy the compliancy of the stabilizer to either enhance or minimize drill bit deviation for accomplishing drilling trajectories.
Referring now to the figures,
The steering assembly may comprise a mud turbine 201 or battery used to power electronic instrumentation devices and tools disposed in the bottom-hole assembly 102. The turbine 201 may be in communication with power generators 207 creating a power supply for the bottom-hole assembly 102 and drill string 100. The steering assembly may also comprise power converters 206 to adapt the electrical output of the power source 201 to an AC power source. The steering assembly may also comprise a steering motor 205, a steering motor control 206, and a steering hammer 203 to steer the bottom-hole assembly 102 and drill string 100 through the formation 105. The steering assembly may also comprise a gear box 204 to control the rpm of the steering hammer 203. Inclination and direction sensors 211 may also be disposed within the steering assembly to detect the location of the bottom-hole assembly 102 downhole. A telemetry network link 212 is also disposed within the steering assembly.
The bottom-hole assembly 102 may also comprise a resistivity tool disposed intermediate point B and point C adapted to obtain evaluation data of a formation 105. Transmitters 215 communicate a signal into the formation 105 and sensors 216 detect the signal as it travels through the formation 105 determining the resistivity of the formation 105. A preferred embodiment of the resistivity tool is disclosed in the patent application Ser. No. 11/776,447 to Snyder, which is herein incorporated by reference for all it contains.
The embodiments of the bottom-hole assembly 102 in
The stabilizer of the present invention is adapted to maximize the stabilizer blade contact with the borehole thereby improving the coupling of formation instrumentation in the stabilizer with the formation, improve signal strength, and reduce noise. The stabilizer blades may be shaped in a spiral to reduce shocks and vibrations.
The stabilizer assembly 300 may have a gap formed in the at least one blade 400 and separating the blade 400 into a first and second portion. Often in oil, gas, or geothermal drilling applications subterranean formations 105 may dictate drilling along deviated paths to avoid hazards or to improve hydrocarbon or geothermal production. It is believed that the gap will reduce the stiffness of the stabilizer assembly 300 allowing the bottom hole assembly to more easily follow a deviated or radial path through the formation 105. A mechanical joint 403 may also be formed in the sleeve 302, segmenting the sleeve 302 to further reduce the stiffness of the stabilizer assembly 300.
The stabilizer assembly 300 may also comprise at least one instrumentation device 402 disposed in the blades 400. The at least one instrumentation device 402 may be powered by the turbine 201, a battery, or a power transmission system from the surface or down hole.
The at least one instrumentation device 402 may also transmit data through a downhole telemetry system. A preferred method of downhole data transmission using inductive couplers 202 disposed in tool joints is disclosed in the U.S. Pat. No. 6,670,880 to Hall, et al, which is herein incorporated by reference for all it discloses. An alternate data transmission path may comprise direct electrical contacts in tool joints such as in the system disclosed in U.S. Pat. No. 6,688,396 to Floerke, et al., which is herein incorporated by reference for all that it discloses. Another data transmission system that may also be adapted for use with the present invention is disclosed in U.S. Pat. No. 6,641,434 to Boyle, et al., which is also herein incorporated by reference for all that it discloses. In some embodiments of the present invention alternative forms of telemetry may be used to communicate with the bottom-hole assembly 102, such as telemetry systems that communicate through the drilling mud or through the earth. Such telemetry systems may use electromagnetic or acoustic waves. The alternative forms of telemetry may be the primary telemetry system for communication with the tool string 100 or they may be back-up systems designed to maintain some communication if the primary telemetry system fails.
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Likewise, hardware 1050 may include volatile 1002 and nonvolatile memory 1003 providing data storage and staging areas for data transmitted between hardware components 1050. Volatile memory 1002 may include random access memory (RAM) or equivalents thereof, providing high-speed memory storage. Memory 1001 may also include selected types of nonvolatile memory 1003 such as read-only-memory (ROM), or other long term storage devices, such as hard drives and the like. Ports 1004 such as serial, parallel, or other ports 1004 may be used to input and output signals uphole or downhole from the stabilizer assembly 300, provide interfaces with the instrumentation devices 402 located in the stabilizer assembly 300, or interface with other tools or sensors located in a drilling environment.
A modem 1005 may be used to modulate digital data onto a carrier signal for transmission uphole or downhole. Likewise, the modem 1005 may demodulate digital data from signals transmitted uphole or downhole. A modem 1005 may provide various built in features including but not limited to error checking, data compression, or the like. In addition, the modem 1005 may use any suitable modulation type such as QPSK, OOK, PCM, FSK, QAM, or the like. The choice of a modulation type may depend on a desired data transmission speed, as well as unique operating conditions that may exist in a downhole environment. Likewise, the modem 1005 may be configured to operate in full duplex, half duplex, or other mode. The modem 1005 may also use any of numerous networking protocols currently available, such as collision-based protocols, such as Ethernet, or token based protocols such as are used in token ring networks.
A stabilizer assembly 300 may also include one or several switches 1006 or multiplexers 1006 to filter and forward packets or combine several signals for transmission over a single medium. Likewise, a demultiplexer may be included with the multiplexer 1006 to separate multiplexed signals received from uphole or downhole.
A stabilizer assembly may include various sensors 1012 located within the stabilizer assembly 300. Sensors 1012 may include data gathering devices such as pressure sensors, accelerometers, hydrophones, piezoelectric devices, inclinometers, pressure transducers, magnetometers, gyroscopes, temperature sensors, gamma ray sensors, neutron sensors, seismic sensors, sonic sensors, mud logging devices, resistivity sensors, induction sensors, nuclear sensors, imaging devices, GPS devices, Hall-effect sensors, permeability sensors, porosity sensors, vibration sensors, electrical potential sensors, geophones or the like. Sensors 1012 may be configured to gather data for transmission up the network to the grounds surface, or may also receive control signals from the surface to control selected parameters of the sensors 1012. For example, an operator at the surface may actually instruct a sensor 1012 to take a particular measurement.
A stabilizer assembly may also include various signal sources 1013 located within the stabilizer assembly 300. Signal sources 1013 may include a seismic source, a sonic source, an explosive, a compressed air gun, a vibrator, a sparker, an electromagnetic device, a density source, a pulse neutron generator or combinations thereof.
Collectively the signal sources 1013 and the sensors 1012 are adapted to measure the properties and conditions of the formation down-hole. Likewise, other instrumentation devices 402 located downhole may interface with the stabilizer assembly 300 to gather data for transmission uphole, or follow instructions received from the surface.
Since a drill string may extend into the earth 20,000 feet or more, signal loss or signal attenuation that occurs when transmitting data uphole or downhole, may be an important or critical issue. Various hardware or other devices of the downhole network may be responsible for causing different amounts of signal attenuation. To reduce data loss due to signal attenuation, amplifiers 1010, or repeaters 1010, may be placed within the stabilizer assembly 300. The amplifiers 1010 may receive a data signal, amplify it, and transmit it uphole or downhole. Like an amplifier 1010, a repeater 1010 may be used to receive a data signal and retransmit it at a higher power. However, unlike an amplifier 1010, a repeater 1010 may remove noise from the data signal.
Likewise, a stabilizer assembly may include various filters 1009. Filters 1009 may be used to filter out undesired noise, frequencies, and the like that may be present or introduced into a data signal traveling uphole or downhole. Likewise, the stabilizer assembly 300 may include a power supply 1007 to supply power to any or all of the hardware 1050. The stabilizer assembly 300 may also include other hardware 1008, as needed, to provide desired functionality to the stabilizer assembly 300.
Whereas the present invention has been described in particular relation to the drawings attached hereto, it should be understood that other and further modifications apart from those shown or suggested herein, may be made within the scope and spirit of the present invention.
Claims
1. A stabilizer assembly on a downhole tool string component, comprising:
- a sleeve slideably attached to a mandrel of the tool string component;
- at least one stabilizer blade is formed in the sleeve and generally follows the length of the sleeve; and
- a gap formed in the at least one blade and separating a first and second portion of the blade.
2. The stabilizer assembly of claim 1, wherein at least one instrumentation device is disposed in the at least one blade to gather subterranean data.
3. The stabilizer assembly of claim 2, wherein the at least one instrumentation device comprises at least one signal source.
4. The stabilizer assembly of claim 3, wherein the signal source is a seismic source, a sonic source, an explosive, a compressed air gun, a vibrator, a sparker, an electromagnetic device, a density source, a pulse neutron generator or combinations thereof.
5. The stabilizer assembly of claim 2, wherein the at least one instrumentation device comprises at least one sensor.
6. The stabilizer assembly of claim 5, wherein the at least one sensor is selected from the group consisting of accelerometers, inclinometers, pressure transducers, magnetometers, gyroscopes, temperature sensors, gamma ray sensors, neutron sensors, seismic sensors, sonic sensors, mud logging devices, resistivity sensors, induction sensors, nuclear sensors, imaging devices, GPS devices, Hall-effect sensors, permeability sensors, porosity sensors, vibration sensors, electrical potential sensors, geophone s or combinations thereof.
7. The stabilizer assembly of claim 2, wherein the at least one instrumentation device is in communication with a downhole telemetry system.
8. The stabilizer assembly of claim 2, wherein the at least one instrumentation device is passively decoupled from the stabilizer assembly.
9. The stabilizer assembly of claim 2, wherein the at least one instrumentation device is actively decoupled from the stabilizer assembly.
10. The stabilizer assembly of claim 1, wherein at least one pocket is formed on an inner diameter of the sleeve.
11. The stabilizer assembly of claim 1, wherein a contour of the blade at an end of the blade has a biased curvature to accommodate mud flow.
12. The stabilizer assembly of claim 1, wherein a plurality of gaps are formed in the at least one blade.
13. The stabilizer assembly of claim 12, wherein the plurality of gaps are offset one from another.
14. The stabilizer assembly of claim 12, wherein the plurality of gaps is force balanced with respect to the rotation of the downhole tool string.
15. The stabilizer assembly of claim 1, wherein the sleeve is segmented.
16. The stabilizer assembly of claim 15, wherein the segmented sleeve is joined through a castle connection.
17. The stabilizer assembly of claim 1, wherein the gap is at least one foot long.
18. The stabilizer assembly of claim 1, wherein the length of the gap is at least twice the width of the blade.
19. The stabilizer assembly of claim 1, wherein the first and second portions are offset.
20. The stabilizer assembly of claim 1, wherein the first or second portion is less than 5 feet long.
Type: Application
Filed: Jul 26, 2007
Publication Date: Jan 29, 2009
Inventors: David R. Hall (Provo, UT), Christopher Durrand (Pleasant Grove, UT)
Application Number: 11/828,901
International Classification: E21B 7/06 (20060101);