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Stabilizer assembly

Stabilizer assembly description/claims

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.

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 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.

FIG. 1 is a perspective diagram of an embodiment of a drill string suspended in a bore hole.

FIG. 2a is a cross-sectional diagram of an embodiment of a first portion of a bottom-hole assembly.

FIG. 2b is a cross-sectional diagram of an embodiment of a second portion of a bottom-hole assembly.

FIG. 3 is a side perspective diagram of an embodiment of a stabilizer assembly.

FIG. 4 is a side perspective diagram of an embodiment of the stabilizer assembly rotated on an axis.

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