Patent Grant
9500034
This application is a 371 U.S. National Stage Application of and claims the benefit of priority to International Application No. PCT/US2014/034535, filed Apr. 17, 2014 and entitled “Bottom Hole Assembly with Wearable Stabilizer Pad for Directional Steering”, the contents of which are hereby incorporated by reference.
This disclosure generally relates to a tool and method for steering the drill string during drilling operations using a wearable stabilizer pad on the bottom hole assembly.
Directional drilling is a process in which the direction in which a wellbore is formed is controlled during drilling. Directional drilling permits wellbores to access specific targets where it would be difficult or impossible to use vertical drilling equipment, such as underground reserves that lie directly beneath surface areas under municipalities, lakes, or other natural or manmade features. Directional drilling also allows multiple wellheads to be grouped together, with the wellbores extending away from the group in various directions underground such as on an off shore platform. Directional drilling is also used to form a near horizontal portion of a wellbore that intersects a greater portion of a petroleum reservoir than a vertical wellbore would penetrate thereby increasing the drainage efficiency of the wellbore.
One general type of directional drilling involves the use of a downhole mud motor having a bent motor housing coupled to the drill string. The drill bit at the end of the drill string may be rotated either by rotating the entire drill string from the surface, or by rotating just the drill bit using the mud motor housing. When rotating the entire drill string from the surface, the bent motor housing rotates along with the rest of the drill string, to drill a nominally straight wellbore section. By ceasing rotation from the surface and rotating the drill bit using just the downhole mud motor, a deviated section is formed at an angle determined by the bend in the motor housing (a process known as “sliding”).
Another type of directional drilling involves the use of a rotary steerable drilling system that controls an azimuthal direction and/or degree of deflection while the entire drill string is rotated continuously. Rotary steerable drilling systems typically involve the use of an actuation mechanism that actively causes the drill bit to deviate from the current path using either a “point the bit” or “push the bit” mechanism. In a “point the bit” system, the actuation mechanism is controlled to deflect and orient the drill bit to a desired position by bending the drill bit drive shaft within the body of the rotary steerable assembly. As a result, the drill bit tilts and deviates with respect to the borehole axis. In a “push the bit” system, the actuation mechanism is instead controlled to selectively push the drill string against the wall of the borehole, thereby offsetting the drill bit with respect to the borehole axis. Yet another directional drilling technique, generally referred to as the “push to point,” encompasses a combination of the “point the bit” and “push the bit” methods.
Systems and methods are disclosed involving directional drilling, whereby wearable stabilizer pads are strategically configured in a manner that improves both the drilling of a deviated wellbore section and the resulting quality of the deviated wellbore section. Whereas conventional stabilizers blades are formed of hard materials and include hard facing deliberately applied to resist wear, the disclosed stabilizer pads include portions that are intentionally designed to wear, to manipulate and vary the resulting wellbore curvature that occurs when drilling a planned deviated wellbore trajectory.
As used herein, “wellbore curvature” is a measure of the change in a well's trajectory, which in some cases may be a 3-dimensional change in a well's trajectory. There are known industry equations for determining certain aspects of wellbore curvature sometimes referred to in the industry as the “dogleg severity” between two points along the wellbore path (e.g., survey stations). Other related terms include “dogleg output” which is the result attained by drilling with a steerable BHA and “dogleg capability” which is a measure of steerable BHA's ability to achieve a certain dogleg output.
Dogleg Severity Equation.
Dogleg Severity (DLS)={ cos−1[(cos I1×cos I2)+(sin I1×sin I2)×cos(Az2−Az1)]MD)
Where;
DLS=dogleg severity in degrees/100 ft
MD=Measured Depth between survey points in ft
I1=Inclination (angle) at upper survey in degrees
I2=Inclination (angle) at lower in degrees
Az1=Azimuth direction at upper survey
Az2=Azimuth direction at lower survey
Example for dogleg severity based on Radius of Curvature.
Survey 1
Depth=7500 ft
Inclination=45 degree (I1)
Azimuth=130 degree (Az1)
Survey 2
Depth=7595 ft
Inclination=52 degree (I2)
Azimuth=139 degree (Az2)
Dogleg Severity (DLS)={ cos−1[(cos 45×cos 52)+(sin 45×sin 52)×cos (139+130)]}×(100÷95)
Dogleg Severity (DLS)=10.22 degree/100 ft.
As further explained below, for instance, the stabilizer pads may include special materials, material geometries, and positioning, to wear at a predictable rate in view of expected geological characteristics of one or more formations or discrete strata in a formation being drilled using a bottom hole assembly including the wearable stabilizer pads of this disclosure. Just as an example, if the expected geological characteristics identified include upper strata of a particularly soft formation, with a lower strata having a greater hardness, the stabilizer pads may be configured with a geometry that initially provides a somewhat aggressive wellbore curvature through the softer, upper strata. The stabilizer pads may further be formed of a softer, wearable stabilizer pad material that is designed to wear appreciably; such that the wellbore curvature is reduced a desired amount by the time the wellbore reaches the harder, second strata. More specifically, the pad geometry and materials may be configured to maintain a desirable wellbore curvature, e.g., 10-12 degrees per 100 feet, throughout the drilling process, despite the change in formation properties when advancing through the upper strata to the lower strata.
As will be appreciated by one of ordinary skill in the art, the disclosed concepts may be adapted for use in a directional drilling system that uses either a downhole mud motor with bent motor housing or a rotary steerable drilling system.
Referring to
In general, and as will be discussed further in the remainder of this document, the BHA 200 includes one or more wearable stabilizer pads 210 that extend radially outward from the BHA 200 to contact the strata of the subterranean geological formation 26 to steer the BHA 200 along a planned deviated wellbore trajectory, e.g., predetermined curved path for a predetermined distance. As noted above, the stabilizer pads may be adapted for use in a directional drilling system that uses either a downhole mud motor with bent motor housing or a rotary steerable drilling system. To reduce or avoid the possibility of having to periodically trip out to change out the stabilizer(s) used in the directional drilling system to achieve different dogleg capabilities, the stabilizer pads are instead configured to wear at a predictable rate, according to expected geological variations in the strata and formations being drilled. For example, such stabilizer pads can be used in horizontal drilling applications in which a vertical wellbore drilling trajectory needs to be deviated to become a horizontal wellbore drilling trajectory. In other implementations the disclosed concepts may be used when the wellbore trajectory incudes a curve section followed by a tangent section.
A stabilizer pad 217 extends radially outward from the bent motor housing 212. In use, the stabilizer pad 217 extends radially to contact a side wall of the wellbore in a like manner as is illustrated with regard to pad 210 in
In some embodiments, the stabilizer pad 217 can be integrally formed as a component of the BHA 201. For example, the stabilizer pad 217 may be molded, cast, machined, or otherwise formed along with a component of the BHA such as the bent motor housing 212 as a unitary assembly. In some embodiments, the stabilizer pad 217 can be attached to the bent motor housing 212 or any other appropriate component of the BHA by a bonding agent, such as a catalyst and resin, or an adhesive. In some embodiments, the stabilizer pad 217 can be attached to a component of the BHA by welds, compression fittings (e.g., dovetail fittings), fasteners (e.g., bolts, screws, clamps), or any other appropriate technique or apparatus for removably or fixedly connecting the stabilizer pad 217 to the BHA.
The upper section 205 includes a stabilizer section 220. The stabilizer section 220 includes a collection of stabilizer pads 222 extending radially from a stabilizer body 224. The stabilizer pads 222 may be formed of a relatively durable material (e.g., steel, tungsten carbide) to provide stability to the BHA 201. In some embodiments, one or more of the stabilizer pads 222 may include a wearable portion and a hardened portion more resistant to wear, or may have different layers of differing hardness and wear resistance as will be discussed further in the description of
One or more stabilizer pads 257 extend radially outward from the sleeve 254 positioned on the bent housing 212. In use, at least one of the stabilizer pads 257 contacts a side wall of the wellbore. In a like manner, as discussed previously with regard to
The upper section 251 includes a stabilizer section 256. The stabilizer section 256 includes a collection of stabilizer pads 259 extending radially from the upper section 251. The stabilizer pads 259 may be configured and made from materials in a manner as discussed previously with regard to stabilizer pads 222 of
As further illustrated in
The upper stabilizer section 266 may also include a connector 270. The connector 270 is formed to mate with a connector 272 formed in a housing of the motor 260. The connectors 270, 272 mate to removably affix the upper stabilizer section 266 to the motor 260. For example, the connectors 270, 272 can be threaded sections.
The BHAs 201, 202, 203 are three examples illustrated in
In use, the stabilizer pad 300 extends radially from the BHA 200 to contact a side wall 303 of the wellbore 60. For example, the stabilizer pad 300 can contact the geological formations 26 at the location indicated as a contact point 311. Contact between the sidewall and the stabilizer pad 300 orients an axis 312 of the bent motor housing and drill bit away from a central wellbore axis 314 at an initial predetermined angle 316. The predetermined angle 316 causes the drill bit or other drilling tool attached to the BHA 200 to drill in an orientation that causes a predetermined deflection (e.g., curve, dogleg) in the trajectory (path) of the wellbore 60 as the wellbore is being drilled.
Contact between the sidewall and the stabilizer pad 300 also causes wear of the stabilizer pad 300 that progressively reduces the thickness 311 of the stabilizer pad 300 and reduces the angle 316 as pad 300 wears as drilling progresses (e.g., reduces the dogleg severity). If the stabilizer pad is completely worn away during the drilling operation, the dogleg capability would be reduced to the angle of the bent motor housing as measured from a central axis of the BHA. The geometry (e.g., the thickness 311) and durability of the materials used in the stabilizer pad 300 results in a deviation of predetermined length and planned deviated wellbore trajectory for the wellbore 60. The stabilizer pad 300 imparts a two or three dimensional change in angular deviation which may increase or decrease the deviation angle 316 as measured from vertical and/or changing the azimuthal direction of the wellbore 60. It will be understood that the change in dogleg severity can be increased or decreased as the pad wears away depending on which stabilizer is designed to wear, e.g., wear on a upper stabilizer leads to an increased dog leg severity with higher inclination and wear on a lower stabilizer leads to a decrease in the dogleg severity. The process of using the stabilizer pad for directional drilling is discussed further in the descriptions of
The stabilizer pad 300 can be positioned on components of the BHA (e.g., bent motor housing, stabilizer assemblies, RSS tool, etc.). In some embodiments, the stabilizer pad 300 can be located on the downhole drilling motor housing. For example, bottom hole assembly (BHA) 200 can include a Moineau motor, also known as a mud motor. In some embodiments, the stabilizer pad 300 can be located on another component of the BHA positioned above the downhole drilling motor.
Referring now to
Referring now to
Referring now to
In certain embodiments, the stabilizer pad 410 can be selected based, at least in part, on its expected wear rate when exposed to strata of geologic formations 25 and 26 such that it will affect a wellbore curvature along the planned deviated wellbore trajectory. The stabilizer pad 410 may be selected based on one or more stabilizer properties which may include, but are not limited to, geometric properties, e.g., shape or thickness, and material properties, such as hardness, durability, or material composition, selected to cause the BHA 200 to drill the wellbore 60 along a predetermined simple or complex nonlinear trajectory (e.g. the deviated wellbore trajectory). In some embodiments, for example, the thickness of the stabilizer pad 410 may be selected to control the radius of curvature of the curve portion 403 (e.g., dogleg severity).
In use, the materials and/or thicknesses of the layers 510-530 can be selected to configure (e.g., mechanically program) the BHA 200 to drill a predetermined path (e.g., planned deviated wellbore trajectory). For example, layer 530 can be relatively hard (e.g., compared to the strata expected to be encountered by the stabilizer pad 500), layer 520 can be relatively soft, and layer 510 can be another relatively hard wear resistant layer. In such an example, layer 530 will contact a wall (e.g., the wall 402 of
At 710, formation properties are obtained for the one or more strata in one or more geological formations through which the planned deviated wellbore trajectory will be drilled. Such properties may include unconfined rock strength, confined rock strength, abrasiveness, dip angle and grain size. The formation properties may be obtained, for example, through seismic, acoustic, and/or electromagnetic logging or surveying with respect to the formation and a borehole within a formation.
At 720, a stabilizer pad is selected such that it will wear a desired amount according to the formation properties sufficient to affect a wellbore curvature along the planned deviated wellbore trajectory. Selecting the stabilizer pad may comprise selecting between different types or designs of stabilizer pads, each with a manufactured or original thickness and a wear rate that depends, at least in part, on the formation properties. Selecting the stabilizer may also comprise selecting the thickness and wear rate and manufacturing or having manufactured a stabilizer pad that meets those specifications. As described above, the thickness and wear rate of the stabilizer pad may affect the trajectory of the deviated wellbore, and the selected stabilizer pad may be characterized by a thickness and wear rate sufficient to affect a wellbore curvature (e.g., dogleg severity) along the planned deviated wellbore trajectory geological
For example, the stabilizer pad 210, 217, 222, 257, 259, 267, 269, 300, 410, 500 and 620 can be formed with a predetermined thickness, and of a material of a known hardness. When the hardness of the pad and the hardness of the subterranean strata of the geological formations 25 and 26 are obtained, an estimate of the rate of wear, e.g., units of stabilizer pad thickness lost per unit of travel of the BHA 200, can be determined. In some implementations, the thickness and wear rate can be selected to offset the BHA 200 for a predetermined distance (e.g., until the stabilizer pad wears out) corresponding to a predetermined length and radius of a curved portion of the wellbore 60 that is to be drilled. The stabilizer pad is positioned on an component of a bottom hole assembly. For example, the stabilizer pad 210, 217, 222, 257, 259, 267, 269, 300, 410, 500 and 620 can be mounted on a component of the BHA 200.
At 730, the drilling of the curve portion of the deviated wellbore trajectory is directionally steered by the wear of the stabilizer pads on the BHA. For example, the BHA 200 can be offset by the stabilizer pad 210, 217, 222, 257, 259, 267, 269, 300, 410, 500 and 620 to cause the wellbore 60 to be drilled along a two or three dimensional curved path.
At 740, the stabilizer pad is worn by contact with the strata of the geological formation to a reduced thickness such that the stabilizer has a change in dogleg capability when the curve portion of the wellbore has been drilled and the bottom hole assembly begins drilling a different portion of the wellbore below the curve portion. For example, as drilling continues along the wellbore from the zone 401a of
In some implementations, the wellbore curvature (e.g., dogleg severity) can be a measure of the predetermined expected three dimensional change in angular deviation that a bottom hole assembly can impart on a proposed wellbore trajectory. For example, two or more of the stabilizer pads 210, 217, 222, 257, 259, 267 and 269, of
Although a few implementations have been described in detail above, other modifications are possible. For example, the logic flows depicted in the figures do not require the particular order shown, or sequential order, to achieve desirable results. In addition, other steps may be provided, or steps may be eliminated, from the described flows, and other components may be added to, or removed from, the described systems. Accordingly, other implementations are within the scope of the following claims.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2014/034535 | 4/17/2014 | WO | 00 |
| Publishing Document | Publishing Date | Country | Kind |
|---|---|---|---|
| WO2015/160354 | 10/22/2015 | WO | A |
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| Entry |
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| International Search Report and Written Opinion of the International Searching Authority issued in International Application No. PCT/US2014/034535 on Jan. 26, 2015; 17 pages. |
| Number | Date | Country | |
|---|---|---|---|
| 20160230465 A1 | Aug 2016 | US |
