Directional drilling involves varying or controlling the direction of a wellbore as it is being drilled. Usually the goal of directional drilling is to reach or maintain a position within a target subterranean destination or formation with the drilling string. For instance, the drilling direction may be controlled to direct the wellbore towards a desired target destination, to control the wellbore horizontally to maintain it within a desired payzone or to correct for unwanted or undesired deviations from a desired or predetermined path.
Thus, directional drilling may be defined as deflection of a wellbore along a predetermined or desired path in order to reach or intersect with, or to maintain a position within, a specific subterranean formation or target. The predetermined path typically includes a depth where initial deflection occurs and a schedule of desired deviation angles and directions over the remainder of the wellbore. Thus, deflection is a change in the direction of the wellbore from the current wellbore path. This deflection may pertain to deviation of the wellbore path relative to vertical or to change in the horizontal direction or azimuth of the wellbore path.
It is often necessary to adjust the direction of the wellbore frequently while directional drilling, either to accommodate a planned change in direction or to compensate for unintended or unwanted deflection of the wellbore. Unwanted deflection may result from a variety of factors, including the characteristics of the formation being drilled, the makeup of the bottomhole drilling assembly and the manner in which the wellbore is being drilled.
Deflection is measured as an amount of deviation of the wellbore from the current wellbore path and is expressed as a deviation angle or hole angle. Deflection may also relate to a change in the azimuth of the wellbore path. Commonly, the initial wellbore path is in a vertical direction. Thus, initial deflection often signifies a point at which the wellbore has deflected off vertical in a particular azimuthal direction. Deviation is commonly expressed as an angle in degrees from the vertical. Azimuth is commonly expressed as an angle in degrees relative to north.
Various techniques may be used for directional drilling. First, the drilling bit may be rotated by a downhole motor which is powered by the circulation of fluid supplied from the surface. This technique, sometimes called “sliding drilling”, is typically used in directional drilling to effect a change in direction of the a wellbore, such as the building of an angle of deflection. However, various problems are often encountered with sliding drilling.
For instance, sliding drilling typically involves the use of specialized equipment in addition to the downhole drilling motor, including bent subs or motor housings, steering tools and nonmagnetic drill string components. As well, the downhole motor tends to be subject to wear given the traditional, elastomer motor power section. Furthermore, since the drilling string is not rotated during sliding drilling, it is prone to sticking in the wellbore, particularly as the angle of deflection of the wellbore from the vertical increases, resulting in reduced rates of penetration of the drilling bit. Other traditional problems related to sliding drilling include stick-slip, whirling, differential sticking and drag problems. For these reasons, and due to the relatively high cost of sliding drilling, this technique is not typically used in directional drilling except where a change in direction is to be effected.
Second, directional drilling may be accomplished by rotating the entire drilling string from the surface, which in turn rotates a drilling bit connected to the end of the drilling string. More specifically, in rotary drilling, the bottomhole assembly, including the drilling bit, is connected to the drilling string which is rotatably driven from the surface. This technique is relatively inexpensive because the use of specialized equipment such as downhole drilling motors can usually be kept to a minimum. In addition, traditional problems related to sliding drilling, as discussed above, are often reduced. The rate of penetration of the drilling bit tends to be greater, while the wear of the drilling-bit and casing are often reduced.
However, rotary drilling tends to provide relatively limited control over the direction or orientation of the resulting wellbore as compared to sliding drilling, particularly in extended-reach wells. Thus rotary drilling has tended to be largely used for non-directional drilling or directional drilling where no change in direction is required or intended.
Third, a combination of rotary and sliding drilling may be performed. Rotary drilling will typically be performed until such time that a variation or change in the direction of the wellbore is desired. The rotation of the drilling string is typically stopped and sliding drilling, through use of the downhole motor, is commenced. Although the use of a combination of sliding and rotary drilling may permit satisfactory control over the direction of the wellbore, the problems and disadvantages associated with sliding drilling are still encountered.
Some attempts have been made in the prior art to address these problems. Specifically, attempts have been made to provide a steerable rotary drilling apparatus or system for use in directional drilling. However, none of these attempts have provided a fully satisfactory solution.
United Kingdom Patent No. GB 2,172,324 issued Jul. 20, 1988 to Cambridge Radiation Technology Limited (“Cambridge”) utilizes a control module comprising a casing having a bearing at each end thereof for supporting the drive shaft as it passes through the casing. Further, the control module is comprised of four flexible enclosures in the form of bags located in the annular space between the drilling string and the casing to serve as an actuator. The bags actuate or control the direction of drilling by applying a radial force to the drive shaft within the casing such that the drive shaft is displaced laterally between the bearings to provide a desired curvature of the drive shaft. Specifically, hydraulic fluid is selectively conducted to the bags by a pump to apply the desired radial force to the drilling string.
Thus, the direction of the radial force applied by the bags to deflect the drive shaft is controlled by controlling the application of the hydraulic pressure from the pump to the bags. Specifically, one or two adjacent bags are individually fully pressurized and the two remaining bags are depressurized. As a result, the drive shaft is deflected and produces a curvature between the bearings at the opposing ends of the casing of the control module. This controlled curvature controls the drilling direction.
United Kingdom Patent No. GB 2,172,325 issued Jul. 20, 1988 to Cambridge and United Kingdom Patent No. GB 2,177,738 issued Aug. 3, 1988 to Cambridge describe the use of flexible enclosures in the form of bags in a similar manner to accomplish the same purpose. Specifically, the drilling string is supported between a near bit stabilizer and a far bit stabilizer. A control stabilizer is located between the near and far bit stabilizers for applying a radial force to the drilling string within the control stabilizer such that a bend or curvature of the drilling string is produced between the near bit stabilizer and the far bit stabilizer. The control stabilizer is comprised of four bags located in the annular space between a housing of the control stabilizer and the drilling string for applying the radial force to the drilling string within the control stabilizer.
United Kingdom Patent Application No. GB 2,307,537 published May 28, 1997 by Astec Developments Limited describes a shaft alignment system for controlling the direction of rotary drilling. Specifically, a shaft, such as a drilling string, passes through a first shaft support means having a first longitudinal axis and a second shaft support means having a second longitudinal axis. The first and second shaft support means are rotatably coupled by bearing means having a bearing rotation axis aligned at a first non-zero angle with respect to the first longitudinal axis and aligned at a second non-zero angle with respect to the second longitudinal axis. As a result, relative rotation of the first and second shaft support means about their respective longitudinal axes varies the relative angular alignment of the first and second longitudinal axes.
The shaft passing through the shaft alignment system is thus caused to bend or curve in accordance with the relative angular alignment of the first and second longitudinal axes of the first and second shaft support means. The shaft may be formed as a unitary item with a flexible central section able to accommodate the desired curvature or it may be comprised of a coupling, such as a universal joint, to accommodate the desired curvature.
U.S. Pat. No. 5,685,379 issued Nov. 11, 1997 to Barr et. al., U.S. Pat. No. 5,706,905 issued Jan. 13, 1998 to Barr et. al. and U.S. Pat. No. 5,803,185 issued Sep. 8, 1998 to Barr et. al. describe a steerable rotary drilling system including a modulated bias unit, associated with the drilling bit, for applying a lateral bias to the drilling bit in a desired direction to control the direction of drilling. The bias unit is comprised of three equally spaced hydraulic actuators, each having a movable thrust member which is displaceable outwardly for engagement with the wellbore. The hydraulic actuators are operated in succession as the bias unit rotates during rotary drilling, each in the same rotational position, so as to displace the bias unit laterally in a selected direction.
PCT International Application No. PCT/US98/24012 published May 20, 1999 as No. WO 99/24688 by Telejet Technologies, Inc. describes the use of a stabilizer assembly for directional drilling. More particularly, a stabilizer sub is connected with the rotary drilling string such that the stabilizer sub remains substantially stationary relative to the wellbore as the drilling string rotates. The stabilizer sub includes a fixed upper stabilizer and an adjustable lower stabilizer. The lower adjustable stabilizer carries at least four stabilizer blades which are independently radially extendable from the body of the stabilizer sub for engagement with the wellbore.
Each stabilizer blade is actuated by a motor associated with each blade, which extends and retracts the blade through longitudinal movement of the stabilizer body relative to the stabilizer blade. Because each stabilizer blade is provided with its own motor, the stabilizer blades are independently extendable and retractable with respect to the body of the stabilizer sub. Accordingly, each blade may be selectively extended or retracted to provide for the desired drilling direction.
U.S. Pat. No. 5,307,885 issued May 3, 1994 to Kuwana et. al., U.S. Pat. No. 5,353,884 issued Oct. 11, 1994 to Misawa et. al. and U.S. Pat. No. 5,875,859 issued Mar. 2, 1999 to Ikeda et. al. all utilize harmonic drive mechanisms to drive rotational members supporting the drilling string eccentrically to deflect the drilling string and control the drilling direction.
More particularly, Kuwana et. al. describes a first rotational annular member connected with a first harmonic drive mechanism a spaced distance from a second rotational annular member connected with a second harmonic drive mechanism. Each rotational annular member has an eccentric hollow portion which rotates eccentrically around the rotational axis of the annular member. The drilling string is supported by the inner surfaces of the eccentric portions of the annular members. Upon rotation by the harmonic drive mechanisms, the eccentric hollow portions are rotated relative to each other in order to deflect the drilling string and change the orientation of the drilling string to the desired direction. Specifically, the orientation of the drilling string is defined by a straight line passing through the centres of the respective hollow portions of the annular members.
Misawa et. al. describes harmonic drive mechanisms for driving first and second rotatable annular members of a double eccentric mechanism. The first rotatable annular member defines a first eccentric inner circumferential surface. The second rotatable annular member, rotatably supported by the first eccentric inner circumferential surface of the first annular member, defines a second eccentric inner circumferential surface. The drilling string is supported by the second eccentric inner circumferential surface of the second annular member and uphole by a shaft retaining mechanism. Thus, upon actuation of the harmonic drive mechanisms, the first and second annular members are rotated resulting in the movement of the center of the second eccentric circumferential surface. Thus the drilling string is deflected from its rotational centre in order to orient it in the desired direction.
Upon deflection of the drilling string, the fulcrum point of the deflection of the drilling string tends to be located at the upper supporting mechanism, i.e. the upper shaft retaining mechanism. As a result, it has been found that the drilling string may be exposed to excessive bending stress.
Similarly, Ikeda et. al. describes harmonic drive mechanisms for driving first and second rotatable annular members of a double eccentric mechanism. However, Ikeda et. al. requires the use of a flexible joint, such as a universal joint, to be connected into the drilling string at the location at which the maximum bending stress on the drilling string takes place in order to prevent excessive bending stress on the drilling string. Thus, the flexible joint is located adjacent the upper supporting mechanism. Upon deflection of the drilling string by the double eccentric mechanism, the deflection is absorbed by the flexible joint and thus a bending force is not generated on the drilling string. Rather, the drilling string is caused to tilt downhole of the double eccentric mechanism. A fulcrum bearing downhole of the double eccentric mechanism functions as a thrust bearing and serves as a rotating centre for the lower portion of the drilling string to accommodate the tilting action.
However, it has been found that the use of a flexible or articulated shaft to avoid the generation of excessive bending force on the drilling string may not be preferred. Specifically, it has been found that the articulations of the flexible or articulated shaft may be prone to failure.
Canadian Patent Application No. 2,298,375 by Schlumberger Canada Limited, laid-open on Sep. 15, 2000, describes a rotary steerable drilling system which includes a pivoting offsetting mandrel which is supported within a tool collar by a knuckle joint and which in turn supports a drilling bit. The angular position of the offsetting mandrel is controlled by an arrangement of hydraulic pistons which are disposed between the offsetting mandrel and the tool collar and which can be selectively extended and retracted to move the offsetting mandrel relative to the tool collar. This system is therefore somewhat complicated, requiring the use of the articulating knuckle joint and a plurality of independently actuatable hydraulic pistons.
U.S. Pat. No. 6,244,361 B1 issued Jun. 12, 2001 to Halliburton Energy Services, Inc., describes a drilling direction control device which includes a rotatable drilling shaft, a housing for rotatably supporting the drilling shaft, and a deflection assembly. The deflection assembly includes an eccentric outer ring and an eccentric inner ring which can be selectively rotated to bend the drilling shaft in various directions. The deflection assembly is actuated by a harmonic drive system, which is a relatively complex and expensive apparatus to construct and maintain.
As a result, there remains a need in the industry for a relatively simple and economical steerable rotary drilling device or drilling direction control device for use with a rotary drilling string which can provide relatively accurate control over the trajectory or orientation of the drilling bit during the drilling operation, while also avoiding the generation of excessive bending stress on the drilling string.
There is also a need for such a drilling direction control device which is adaptable for use in a relatively small diameter embodiment.