CA2081806C

CA2081806C - Apparatus for drilling a curved subterranean borehole

Info

Publication number: CA2081806C
Application number: CA002081806A
Authority: CA
Inventors: Tommy Melvin Warren; Houston Browning Ii Mount; Warren Jeffrey Winters
Original assignee: BP Corp North America Inc
Current assignee: BP Corp North America Inc
Priority date: 1991-11-01
Filing date: 1992-10-30
Publication date: 2005-05-10
Anticipated expiration: 2012-10-30
Also published as: MX9206267A; CA2081806A1; US5213168A; RU2072419C1

Abstract

A curve drilling assembly operable with a rotary drill string is provided for drilling a curved subterranean borehole. The assembly includes a curve guide, a rotary drill bit, an imbalance force assembly, and a bearing assembly. The curve guide is connectable with the drill string for deflecting the drill string toward the outside radius of the curved borehole. The imbalance force assembly, which preferably is provided by selectably disposing cutting elements on the drill bit, is rotatable with the drill string for creating a net imbalance force along a net imbalance force vector substantially perpendicular to the longitudinal axis of the drill bit during drilling. The bearing assembly is rotatable with the drill string and is located in the curve drilling assembly near the cutting elements of the drill bit for intersecting a force plane formed by the longitudinal bit axis and the net imbalance force vector and for substantially continuously contacting the borehole wall during drilling.
Preferably, the boring assembly include. a substantially smooth wear-resistant sliding surface. The curve guide includes a mandrel rotatably disposed within a housing. It contact ring may be provided at either the uphole or the downhole end of the mandrel for contacting the borehole wall and supporting the radial force component created by the deflection of the drill string at the end of the mandrel. A flexible joint may be connected to the end of the mandrel adjacent the contact ring for drilling curved boreholes having a short radius of curvature.

Description

2~~~~~~f PATENT

WARREN/WINTERS/MOUNT
APPD~RA'ftls 8'ON DRILLIN~ A CURtIED BUBTERRA81E1lN BOREHOLE
BACKGROUND OF THE INVENTION
1. Field of the Invention This invention relates to apparatus for drilling the curved portion of a subterranean borehole. More particularly, the invention relates to apparatus capable of initiating and controlling curved boreholes when drilling an oil or gas well.
2. Setting of the Invention In producing subterranean fluids, such ms oil and gas, thousands of feet of substantially vertical well bore or bvrehole are drilled into the earth to make a relatively few Peat of contact with the producing formation or strata, since the formation often has limited vertical depth (some formations have as little as five feat) and much greater horizontal extent (e. g., thousands of feet).
It is often desirabl~ to increase the contact area of the borehole with the formation to increase the production rate of the well.
Hydraulic fracturing is one known method of increasing the contact area which has baa~1 proven to increase production. Hydraulic fracturing is difficult to control.
Anothsr known method of increasing the contact area of the borehola with the formation, which is the subject of this invention, is to drill horizontally or laterally into and through S.

'hs formation. In order to do so, it is necessary to be able to dr:Lll a cuxvat~ borshole, or curved section of barehole, from a substantiallx straight (normally vertical) borehols to the desired trajectory. Because of the limited vertical depth o! some lo~rmations, in order to hit the formation with the curved borehole, it is desirable to be able to drill a curved borshols having a predictable radius o! curvature. Even though it has the potential o! being the least expensive and most reliable method o! enhancing production rates by increasing the contact area o! the borehole with the formation, curve drilling is not widely used at the present time because o! shortcomings in the known curve drilling assemblies, such as in their durability, in their maintenance and operational expsnsas, and in their ability to drill a curved borehole having a predictable radius o! curvature.
In order to accurately, repeatably, and predictably drill a curved subterranean borahols having a predstsrminad radius of curvature it is known that it is nacsssary to (1) initiate and maintain a deflection o! the drill bit axis with respect to the axis o! the borshols and (2) to control the azimuthal direction of the dsllaction in the borehole. Prior curve drilling assemblies hays created and maintained the deflection by creating and maintaining a lateral force near the drill bit which forces the drill bit against the borehole sidewall in the desired azimuthal direction, and have controlled the azimuthal direction of the deflection by using a collmr which engages the borshola sidewall or by using the weight of the drill string (weight-on-bit) to hold the 2~:~L~~~
'eflection-creating device in position. The azimuthal direction is controlled so that the radius of curvature of the curved borehole will exist in a single radial plane, e.g., so the borehols will not have a helical or cork-screw trajectory and will drill in a single compass direction with respect to the borehole axis.
For example, U.S. Pat. Nos. 2,712,434; 2,730,328; 2,745,635;
2,819,040; 2,919,897; and 4,699,224 disclose using a collar on the drill string to create a lateral force which forces the drill bit into the borehols sidswall. U.S. Pat. Nos. 2,712,434 and 4,99,224 use a collar having an eccentric bore with the drill string passing through the eccentric bore to create the lateral force and the deflection. U.S. Pat. Nos. 2,730,328 and 2,745,635 effectively treats a collar having an eccentric bore by extending shoes or springs from th: collar when the collar is subjected to weight-on-bit so that the collar and drill bit are forced to one side of the borshols with the drill bit being forced into engagement with the borshola sidswall. U.S. Pat. No. 2,819,040 uses a deflecting wedge which extends frog the collar when the collar is subjected to weight-on-bit in order to create a lateral force which forces the drill bit into sngagsasnt with the borehol. sidswall. U. s. Pat. No.
2,919,897 discloses wing an eccentrically-shaped mandrel rotatable within an aacsntsically-shaped deflection bearing to create a lateral forts which forces the drill bit to one aids of the borehols.
Oncs ths,collar is positioned to force th. drill bit in the desired azimuthal direction, sidewall engaging ribs (U. S. Pat. Nos.

2~~~~~~a~
,730,328 and 2,745,635), splines (U.S. Pat. No. 2,919,897), or angled projections or blades (U.S. Pat. Nos. 2,819,040 and 4,699,224) are used to prevent rotation of the collar with the drill string in order to fix the position, or rotational orientation, of the collar in the borehole and thereby fix the axi,muthal direction of the deflection and the drill bit in the borehols. In U. S. Pat. Nos. 2, 819, 040 and 4, 699, 224 the projections or blades are angled to allow the collar to rotate with the drill string in one direction and to prevent rotation of the collar with l0 the drill string in the other direction.
The above-mentioned patents also disclose apparatus for engaging the collar to the drill string for rotation with the drill string in order to rotationally orient the collar and thereby select the azimuthal direction of the deflection in the borehole.
For example, U.S. Pat. Nos. 2, 730, 328 and 2, 745, 635 use the absence of weight-on-bit or axial loading to engage the collar to the drill string and the presence of weight-on-bit to disengage the collar from the drill stringf U.S. Pat. No. 2,819,040 uses a hydraulically actuated piston= and U.S. Pat. Nos. 2,712,434 and 4,699,2.24 use a spring-actuated detent or cog which acts as a one-way clutch mechanise. O.S. Pat. loo. 2,919,897 uses a key on the collar which engages a k~yvay in the drill string when the drill string is lifted and which disengages when weight is placed on bit and tr,e splines on the collar have engaged the barehole to lift the collar with respect to the drill string and drill bit.
U.S. Pat. Nos. 2,687,282; .3,156,310; 3,398,804? 4,523,652; ark I
2~~ ~~
,699,224 disclose the use of a tlexible joint, such as a knuckle joint, to increase the magnitude of the deflection in order to drill a curved borehole having a shorter radius of curvature. U.S.
Pat:. Nos. 2,687,282; 3,398,804; and 4,523,652 disclose using a stationary derlecting surface in the vertical borehole to initiate andl azimuthally direct the detlection of the drill bit and using the deflecting surface and weight-on-bit to control or maintain the desired azimuthal direction.
U.S. Pat. Nos. 3,156,310 and 4,699,224 use a collar in combination with the knuckle joint to initiate the deflection and to control or maintain the azimuthal direction of the deflection in the borahole. Ira U.S. Pat. No. 3,156,310 blades extend from the collar to dellect the collar and knuckle joint to one side of the borehole and to thereby deflect the drill bit against the opposite wall. The blades also serve to engage the borehole~sidewall to prevent rotation o! the collar and to maintain the azimuthal direction of the deflection. The collar may be on either side of the knuckle joint. U.S. Pat. No. 4,699,224 discloses angled blades extending lros the thick side of an eccentrically bored collar. As in U.S. Pat. No. 3,156 310, the blades both dellect the collar to one aido o! the borehole and engage the sidewall. In U.S. Pat. rro.
4,699,224 th1 Collar is on the uphole side of the knuckle joint.
In Q.B. pat. NOt. 2,919,89'7; 3,156,310; and 4,699,224 the weight of the drill string is carried in the non-rotating collar during drilling which cremtes a single wear-point. The deflection creates a radial component o! the weight-on-bit which is directed '.owards and supported by the portions of the collar on the outside radius of the deflection and of the borehole.
U.S. Pat. Noa. 2,687,282 and 4,699,224 disclose forcing the drill bit to drill upward by leveraging the drill bit into the borehole sidewall using a reamer ~or stabilizer as a fulcrum between th~~ drill bit and the knuckle joint. U.S. Pat. Nos. 3,398,804 and 4, 449, 595 use a reamer, and U. S. Pat. No. 3, 156, 310 uses stabilizer blades,'respectively, to leverage the drill bit into the borehole sidewall. This leveraging of the drill bit creates a lateral or radial force on the drill bit and also allows cutting forces to be leveraged from the drill bit into the drill string.
U.S. Pat. NOS. 2,687,282, 3,398,804, 4,449,595, 4,523,652, and 4,699,224 disclose using a reamer to ream the sidewall o! the borehole. U.S. Pat. No. 4,523,652 discloses a curve drilling assembly in which the sidewall of a reamer is shaped to match the desired radius o! curvature of a borehole in attempting to stabilize the downhols assembly when drilling into intervals of varying hardness. U.S. Pmt. No. 4,449,595 discloses a curve drilling assembly in which the reamer is designed to be overgauged, tapered, and non-cutting at its leading, downhola and in attempting to stabilize the rsa~er and prevent preferential upward cutting by the reamer. It is known that use of a reamer will both enlarge or "overgauge" the bosehole diameter with respect to the drill bit diameter and will craate lateral forces on the curve drilling assembly. Use o! the reamer as a fulcrum will increase the overgauging o! the borehole by the reamer because o! the lateral 'orces exerted on the reamer.
U.S. Pat. Nd.°2,9:9,897 discloses biasing a selected "master"
cutter on the drill bit into engagement with the borehole wall in the direction of the desired deflection and out o! engagement with the borehole wall when the master cutter is oriented diametrically opposite to the direction of the desired deflection. U.S. Pat. No.
2, 919, 897 does not disclose or suggest controlling or modifying the gauge cutting of the remaining cutters on the drill bit.
U.S. Pat. No. 4,815,342, which is owned by the assignee of the this application, discloses a method of modeling the cutting surfaces on a drill bit, calculating the forces acting on the cutting surfaces, and calculating the position of balancing cutters which may be placed on the drill bit in order to reduce the imbalance force created by the cutters.
U. S. Pat. Nos. 5, 010, 789 and 5, 042, 596, which are owned by the assignee of the this application, disclose a drill bit and method of making a drill bit having a plurality of cutting elements (also referred to as "cutters") and a relatively smooth bearing zone. The cutting elements are positioned to cause the net imbalance force generated by the cutting elements to bs directed towards the bearing zone in order to prevent backward whirl of the drill bit during drillitfg. 8ackvard whirl results in severe impact loading of the cuttsrs on tht drill bit and is normally very detrimental to drill bits. Backward whirl is a motion that results in the longitudinal drill bit canter moving counterclockwise around the borehole axis during drilling (the normal drilling direction being ~~j'~..
lockwise) . In iJ. S. Pat. No. 5, 042, 596 the net radial imbalance force is disclosed as being created along a net radial imbalance force vector and as having sufficient magnitude to substantially maintain a sliding surface disposed in a cutter devoid region on the gauge portion of the drill bit in contact with the borehale wall.
Despite the many prior attempts to create a reliable curve drilling assembly, a need exists for a cure: drilling assembly which will drill a curved borehole having a more reliable and predictable radius of curvature. The patents referenced in this application illustrate the long-felt need. for a curve drilling assembly which will drill a curved borehole having these properties. There is also a commercial need for a curve drilling assembly which will drill a curved borehole with minimal maintenance and which is relatively inexpensive and easy to use.
SU1~ARY OF THE INVENTION
The present invention is contemplated to overcome the above-described problems and meet the abov~-described needs. For accomplishing this, the present invention provides a novel and improved curve drilling assembly.
The mentors discovered that, in order to drill a curved borehole halrit'g a predictable radius of curvature, it is necessary to control the gauge cutting by the drill bit and the forces exerted on the bit during drilling. To achieve this control, the inventors discovered that it is necessary to control the forces s 2~~~~.
~.reated by the drill bit during drilling and to control the lateral forces created by the deflection in the curve drilling assembly.
Tha inventors discovered that the performance of a curve drilling assembly is improved by using the low friction drill bit disclosed in assignee's prior U.S. Patent No. 5,042,596; that performance is further improved by repositioning the gauge cutting elements and imbalance forces on the bit to reduce overgauging;
that performance is further improved by eliminating other gauge cutting surfaces Eros the curve drilling assembly; that performance is further improved by reducing the transfer of any lateral forces created by the deflection in the curve drilling assembly to the drill bit; and that performance and durability are further improved by providing a rotating contact on the rotating drill string near the deflection to transfer the lateral force component of the weight-on-bit created by the deflection to the borehola wall.
By controlling the forces created by the drill bit during drilling and controlling the lateral forces created by the detlectioa in the crows drilling assembly, the present invention provides a curve drilling assembly of long-sought and previously unknown accuracy, predictability, and durability.
It is an advantage of the present invention to provide a curve drilling assembly which will drill a curved borahole having a reliably predictable radius of curvature.
It is an advantage o! the present invention to provide a curvo drilling assembly which will drill curved boreholes having long, mediua, or short radii of curvature.

It is an advantage o! the present invention to provide a curve drilling assa~ably which requires relatively little maintenance, which is constructed and arranged to facilitate maintenance, and which is relatively inexpensive and easy to use.
Accordingly, the present invention provides a curve drilling assembly which is connectable to a rotary drill string for drilling a curved subterranean borehole having an inside radius and an outside radius. The assembly comprises curve guide means connectable with the drill string for deflecting the drill string toward the outside radius of a curved borehole; a rotary drill bit;
imbalance force means, rotatable with the drill string, for creating a net imbalance force along a net imbalance force vector substantially perpendicular to the longitudinal axis of the drill bit during drilling; and bearing means, rotatable with the drill string and located in the curve drilling assembly near the cutting elements of the drill bit fox intersecting a force plane formed by the longitudinal bit axis and the net imbalance force vector and !or substantially continuously contacting the borahole wall during drilling.
The imbalance force means can be created and controlled in several ways and preferably is created and controlled by selecting the arrangement o! the cutting elements on the drill bit. Thus, in a preferred embodiaent of the invention, the cutting elements are disposed for creating the net imbalance force along the net imbalance force vector. Preferably, the cutting elements are disposed for creating a radial imbalance force along a radial ~~.'~~~~~
tmbalanca force vector during drilling and for creating a circumferential imbalance force along a circumferential imbalance force vector during drilling, and the net imbalance force vector is a resultant of the radial imbalance force vector and the circumferential imbalance force'vector.
In the preferred embodiment, the bearing means is disposed within a substantially continuous cutting element devoid region disposed on the gauge portion of the drill bit. Preferably, the bearing means is a substantially smooth wear-resistant sliding surface for slidably contacting the borehole wall during drilling.
Mores preferably, the sliding surface has a size su!liciant to encompass the net imbalance force vector as the net imbalance force vector moves in response to a change in hardness o! the borehola wall during drilling. In another aspect of the invention, the cutting elements are disposed for causing the net imbalance force to remain directed toward the bearing means during drilling and during drilling disturbances. In another aspect of the invention, the sliding surlaca is located on the gauge portion o! the drill bit substantially opposite to a gauge cutting element and the sliding surlaco is constructed and arranged to move the gauge cutting olaa~ont into deeper cutting engagement with the borehole wall when the gauge cutting element is about axially coincident with the inside radius o! the curved borehole.
The curve guide moans includes a mandrel rotatably disposed in a housing. Preferably, the housing comprises borehola engaging means for preventing rotation of the housing with the mandrel 2~~~.~~
-wring drilling and mandrel engaging means for rotating the housing with the mandrel when the mandrel is rotated in an opposite direction to the drilling direction. Preferably, contact means are provided at the uphole end or the downhole end of the mandrel for contacting the borehole wall and supporting the radial force component of the weight-on-bit created by the deflection. The invention also provides a flexible joint which may be connected at the end, of the mandrel adjacent the contact means for drilling curved boreholes having a short radius of curvature.
BRIEF DESCRIPTION OF THE DRAWIN-a The present invention will be better understood by reference to the examples of the following drawings:
Figure 1 is a schematic representation of an embodiment of a curve drilling assembly of the present invention which may be used !or drilling curved boreholes having a long radius of curvature.
Figure 2 is a schematic representation of another embodiment of the cuxwe drilling assembly of the present invention.
Figure 3 is a side view of a subterranean drill bit in accordance with the present invention.
Figure 4 is i tog view of Figure 3 showing the face portion of the drill bit.
Figure S is anothls side view of the drill bit shown in Figure ~s Figure f is a top view of Figure 5.
Figure ~ is a schematic side view of a subterranean drill bit.

2~~.
Figure 8 is a schematic face or longitudinal view of a subterranean drill bit which is used to illustrate the forces acting on the drill bit during drilling.
Figure 9 is s schematic face or longitudinal view of a subterranean drill bit which is used to illustrate the circumtsrsntial imbalance force acting on the drill bit during drilling.
Figure 10 is a schematic face or longitudinal view of a subterranean drill bit rotating in a borehole which is used to illustrate static stability of the drill bit.
Figure 11 is a schematic face or longitudinal view of a drill bit rotating in a borahols which is used to illustrate backward whirl of a drill bit.
Figure 12 is a schematic face or longitudinal view o! an embodiment of s subterranean drill bft in accordance with the present invention.
Figure 13 is a schematic face or longitudinal view of an embodiment o! a subterranean drill bit in accordance with the present invention.
2o Figure i4 is a acheaatic sectional side view of an embodiment of a drill bit of the present invention which illustrates the action of tlus~ drill bit when the gauge cutting elements are adjacent the inside radius of a curved borshols.
Figure 15 is a schsaatic side sectional view similar to Figure 14 which illustrates the action of the drill bit when the gauge cutting elements are adjacent the outside radius of a curved ~~~~vL~
~rehola.
Figure ib is a sectional view of an embodiment of the curve drilling assembly of the present invention.
Figure 17A is a sectional view taken along line 17-17 of Fig~ura 16. w Figure 178 is a sectional view taken along line 17-17 of Figure 16 which illustrates another embodiment of the borehole engaging means of the present invention.
Figure 18 is a sectional view taken along line 18-18 of Figure 16.
Figure 19 is a sectional view taken along line 19-19 of Figure ib.
Figure 20 is a sectional view of another embodiment of the curve drilling aasemlaly of the present invention.
Figure 21 is a schematic representation of an embodiment of the curve drilling assembly of the present invention used for drilling curved boraholss having a short radius of curvature.
Figure 211 is a back view of the flexible joint illustrated in Figure 21.
Figure 21H is a trout view of the flexible joint illustrated in Figure Z1.
Figure ZZ ie a sectional view of a flexible joint used with the presa~t invention.
Figure 22A is a sectional view of another embodiment of a flexible joint of the present invention.
Figure 23 is a plot of test data illustrating the parformanc~

f ,a prior curve drilling assembly.
Pigur!~24 is a plot of test data illustrating the performance of another prior curve drilling assembly.
Figure 25 is a plot of test data illustrating the performance of an embodiment of a curve drilling assembly of the present invention similar to that shown in Figure 20, but using the flexible joint of Pigurs 22A.
Figure 26 is a plot of test data illustrating the perfonaance of an embodiment o! a curve drilling assembly of the present l0 invention similar to the one shown in Figure 16, but using the flexible joint of Pig 22A.
Figure 27 is a plot of test data illustrating the performance of an embodiment o! a curve drilling assembly of the present invention siailar to the one shown in Figure 20 and using the flexible joint of Pig 22.
DETAILF~ D~SG'RT~~ON OF THE p,,~;EFEItR,F~D EMBODTM~hTQ
The preferred eabodiments o! the invention will now be described with roleronce to the drawings, wherein like reference characters refer to liJco or corresponding parts throughout the drawings.
i.0 j Figs. 1-2211 psossnt preferred embodiments of a curve drilling assembly 20 according to the present invention. As exemplified ~n Pig. 1, in the preferred embodiment, the assembly 20 is connected 2~~.c~~r~>
atween a rotary drill bit 22 and drill string 24 used in drilling a curved bor:hole 26 of an oil or gas well. In accordance with the invention, the curve drilling assembly 20 is operable with a rotational drive source, not shown in the drawings, for drilling in subterranean earthen materials to create a borehole 26 having a borehole wall 28. The rotational drive source may comprise a commercially available drilling rig with a drill string for connection to commercially available subterranean drill bits. The apparatus 20 may ba used to drill a curved borehols in virtually any type of environment, e.g., water wells, steam wells, subterranean mining, etc. The assembly 20 also may ba used for initiating a curved borehole 26 from a substantially straight borehol~.
Referring to Fig. 2, in order to drill a curved borehole 26, it is necessary to initiate and maintain a deflection 30 of the drill bit axis 31 with respect to the longitudinal axis 32 of the drill string 24 (as well as with respect to the longitudinal axis of the borehols 26) and to control the azimuthal direction of the deflection in the borahola 26. During drilling, axial forces F"
commonly referred to as weight-on-bit, are exerted on the drill string 24 and drill bit 22 in order to force the drill bit 22 into the subtsrran~an loraation. The deflection 30 creates s radial or lateral force coaponent F" of the axial force in the curve drilling asasmbly 20. Rotation of the drill bit during drilling also creates radial, or lateral, forces on the drill bit 22 and drill string 24.
Ths inventors discovered that, in order to drill a curved ~rehols having a predictable radius of curvature it is necessary to control the integrity of the curve-creating structure of the curves drilling assembly by making the assembly drill a substantially gauge borehole (i.e., a borehols of predictable diameter with respect to the diameter of the drill bit); and that this is accomplished by controlling the forces acting on the bit-and and on the deflection-end of the assembly.
Through extensive study of the structural configuration and dynamics of a curve drilling assembly in a curved borehole, the inventors discovered that only a small amount of overgauging of the borehole is required to impair the ability of the assembly to reliably drill a curved borehole. ~~Overgauged" or "overgauging", as used hereinafter, refers to a borehols having a diameter which is larger than the drill bit drilling the borehola by an uncontrolled and unpredicted amount. For example, the invsntors° research established that 5/16 inch of overgauging by a drill bit having 3-7/8 inch outside diameter used with a curve drilling assembly designed to drill a radius of curvature of 20 feet is sufficient to prevent the drilling o! a curved borshols or to cause an inconsistent radius o! curvature; and that as little as 1/e inch of overgauging by the 3-7/a drill bit in a curve drilling assembly designed to drill a radius of curvature o! 25 feet can cause the radius of cusvature drilled to be 60 feet. It should be noted that, depending upon the siae and shape of the drill bit and the radius of curvature of the curved borehole, the angle or skew of the longitudinal axis of the drill bit with respect to the longitudina 1 2~3~.~~
,xia of the previously drilled borehole may produce a slightly oversized borehole (for example, one-sixteenth inch oversized when dr:Llled with a 3-15/16 inch drill bit drilling a curved borehole with a 30 foot radius of curvature). However, as long as this oversizing is predictable and controllable the curve drilling assembly can be designed or adjusted to drill a borehole having a constant, predictable radius of curvature.
Referring to the example of Fig. 1, in accordance with the invention, the curve drilling assembly 20 includes curve guide means 34 connectable with the drill string 24 for deflecting the drill string 24 toward the outside radius Ro of a curved borehole 26; drill bit 22 having a base portion 36 disposed about a longitudinal bit axis 31 for connection through the curve guide means 34 with the drill string 24, a gauge portion 40 disposed about the longitudinal bit axis 31 and extending trom the base portion 36, a face portion 42 disposed about the longitudinal bit axis 31 and extending from the gauge portion 40, and a plurality of cutting elements 44 disposed on the face portion 42; imbalance force means 46 for creating a net imbalance force along a net imbalance force vector F, substantially perpendicular to the longitudinal bit axis 31 during drilling; and bearing means 48 located in tae curve drilling assembly 2o near the cutting elements 44 for intersecting a force plane P, (best seen in Fig. 3) formed by the longitudinal bit axis 31 and the net imbalance force vector F; and foe substantially continuously contacting the borehole wall 28 during drilling. The invention also includes contact means so ~~~ ~.'~~~~
'or~contaating the borahole wall 28 and supporting the radial force component F" on the borehole wall 28 during drilling.
In Section 2.0, the drill bit 22, imbalance force means 46, and bearing means 48 are described as controlling the forces created near the drill bit 22. In Sectian 3.0, the curve guide means 34 and contact means 50 are described as controlling the torcaa created near the deflection 30. In Section 4.0 a flexible joint is described which enhances the ability of the assembly 20 to drill curved boreholes having a short radius of curvature. In Section 5.0 test data is presented which compares the performance of the cuxws drilling assembly of the present invention with the performance of prior curve drilling assemblies. As will be apparent to one skilled in the art in view of the disclosure contained herein, the lestates at the invention may bs used, independently or in various combinations, with virtually any curve drilling assembly. Preferably all o! the features o! the invention are used in combination to maximize the benefits of the invention.
2.0 DRILL HIT CO~'$Qj~
In this Section, the drill bit 22, imbalance force means 4s, and bearing msanm 4~s are described as controlling. the forces created nsas the drill bit 22. The drill bit 22 is discussed in subsection Z.l. T?u bearing means 48 is discussed in subsection 2.2. The imbalance force means 46 is discussed in subsection 2.~.
2.1 psill Bit l~ preferred embodiment of a fixed cutter subterranean drill bit 22 is shown in Figs. 3 and 4. Fig. 3 shows a side view, and Fig. 4 shoots- a longitudinal view, corresponding to a view of an operational drill bit taken from the bottom of the borehole. Drill bit: 22 includes a base portion 36 disposed about longitudinal bit axis 31 for receiving the rotational drive source. Base portion 36 includes a connection (not illustrated) that can be connected in a known manner to the drill string 24. Longitudinal bit axis 31, a theoretical concept used for reference purposes and to facilitate description, extends through the center of base portion 36.
"Radial" as the fete is used in this document, refers to positions located or measured perpendicularly outward from longitudinal bit axis 31, for example, as shown in Fig. 3. "Lateral", as the term is used in this document, refers to positions or directions located or measured transversely outwardly from bit axis 31, although not necessarily perpendicularly outwardly lrom the bit axis 31. ~~Axial°
or "longitudinal" refers to positions or directions located or measured along or coextensively with the bit axis 31.
The drill bit gauge portion 40 includes a cylindrical portion substantially parallel to bit axis 31. Because of the substantially cylindrical sbaps o! gauge portion 40, the gauge portion 40 has a gauge radius lt~ aeasu=ed radialiy outward and perpendicularly from longitudinal bit axis 31 to the surface of the gauge portion, as shown in Fig. 4. Gauge portion 40 preferably includes a plurality of grooves or channels 5~ extending parallel to bit axis 3i to facilitate the reaoval of rock cuttings, drilling mud, and debris.

2~~~:~.~"~u~
Gauge portion 40 and face gortion 42 can be considered to meet at a line 54 (Fig. 5) at which the radius of the drill bit 22 begins to transition from having the gauge radius Re. Line 54 therefore represents the circumference of the gauge portion.
The drill bit 22 shown in Fig. 1 has a curved profile, i.e., the cross-section o! face portion 42, when viewed from a side view perpendicular to the bit axis, has a concave profile. The face portion 42, when viewed from the side-view perspective, may, for example, have a spherical, parabolic, or other curved shape. Such profiles, however, are not limiting. For example, the face portion may be flat or mmy have an axially extending cavity as shown in Figs. 3-6.
In accordance with the invention, the subterranean drill bit 22 further includes a plurality of cutting elements 44 fixedly disposed on and projecting from the face portion and spaced from ons anothor. Preferably, the invention further includes at least ones gauge cutting element 56, spaced from the lace portion cutting elements 44, fixedly disposed on and projecting from the gauge portion.
Each o! the cutting elements 44, 56 preferably comprises a poly-crystmllin~ diaaond compact material mounted on a support, such as a carbide support. The cutting elements may, o! course, includs othsr mat~sials such as natural diamond and thermally stable polycrystmllin~ diamond material. Each o! the cutting elements 44, 56 has a bas. disposed in face portion 42 or gauge portion 40, respactivsly. Each of the cutting elements has a 2i C7 V 9. V '9,I 1-r ,4 vtting edgy for contacting the subterranean earthen materials to be cut.
As shown in Fig. 4, cutting elements 44 are positioned in linear patterns along the radial dimension on face portion 42. This is by way of illustration, however, and not by way of limitation.
For example, cutting elements 44 may be positioned in a nonlinear pattern along a radial dimension of the face portion 42 to form one or mots curved patterns (not illustrated) or they may bo positioned in a nonuniform, random pattern on the face portion (not illustrated).
As embodied in the drill bit of Figs. 3-6, the gauge cutting elements 56 are similar or identical to cutting elements 44.
Cutting elements 56 are disposed on gauge portion 40 with their cutting edges positioned at a uniform radial distance from bit axis 31 to define gauge radius R~, as shown in Figs. 4 and 6. Gauge cutting elements 56 are spaced from cutting elements 44 and from one another. As shown in Fig. 3, gauge cutting elements 56 may be aligned with corresponding ones of cutting elements 44, and two or more gauge cutting elesents 56 preferably extend linearly along the gauge portion 42 in thlr axial direction of the bit 22. The gauge cutting eleasnta ss define the gauge or diametrical dimension of the borehol~ wall 2~, and serve to finish the borehole wall. The gauge cutting eleaonts 56 prolong bit lifetime, given that gauge cutting elements S6 closer to face portion 42 will wear faster than gauge cutting elements 56 farther from the lace portion so the gauge cutting elements 56 wear in sequential rather than zz 2~~~~~.~~
~imultanaous fashion. The cutting edge of the gauge cutting elements 56a farthest from the face portion 42 may be constructed and arranged to provide a cutting edge which extends axially along gauge radius 1~, as does the substantially flat cutting edge of cutting element 56a. Such gauge cutting elements are commonly known as "gauge trimmers" and are used because their axially extended cutting edge wears longer than does the apex of a rounded cutting edge. A gauge cutting element 56 with a rounded cutting edge becomes "undergauge" as soon as the apex of the edge wears down.
The number of individual cutting elements 44, 56 en the drill bit 22 can vary considerably within the scope of the invention, depending on the specific design and application of the drill bit.
Tha prototype drill bit 22 is 3-15/16 inches in diameter and includes at least 15 individual cutting elements, but this is not limiting. For exempla, a drill bit having an outside diameter of 8.5 inches could have between 25-40 individual cutting elements, approximately 17 to 28 on the face portion and approximately 8 to 12 on the gauge portion. A 17.5 inch diameter bit might have over 100 separate cutting elements. It is known that commercially available drill bits used in subterranean drilling range from bore sizes o! ~ incha~ to Z:f inches, although the most widely used sizes used in drl131ng cusvid boraholes fall within the range of 3-7/8 to 17-1/2 inchal.
Drill bit 2Z includes an internal fluid flow channel (not illustrated) in fluid comaunication with the drill string bore 58, and a plurality of nozzles 57 disposed on face portion 42 and in Fluid communication with the drill bit flow channel. The flow channel and nozzles 57 provide a lubricating fluid such as drilling mud to face portion 42 of the drill bit 22 during the drilling to lubricate the drill bit and remove rock cuttings, as is well known to those skilled in the art.
2.2 Bearinq means Referring to Figs. 3-6, the invention includes bearing means 48 located in the curve drilling assembly near the cutting elements 44 for intersecting a force plane P~ (Fig. 4) formed by the net imbalance force vector Fi and the longitudinal bit axis 31. The bearing means 48 may ba located on the drill string 24 adjacent the drill bit 22, for example, on a drill collar or stabilizer adjacent the bit, as would bs understood by one skilled in the art in view o! disclosur. contained herein. Preferably, the bearing means 48 is within a substantially continuous cutting element devoid region so and is disposed on the gauge portion 40 of the drill bit 22.
Preferably, the cutting element devoid region 60 extends onto the face portion 42 of the bit 22.
Cutting slsasnt devoid region 60 comprises a substantially continuous r~gion o! gmugs portion 40 and face portion 42 that is devoid of cutting sls~asnts 44, 56 and abrasive surfaces. Cutting element dseoid region 60 intersects and is disposed about force plane P" which is torasd by the longitudinal bit axis 31 and net imbalance torte vector F,. Foree plane P, is a theoretical concept used !or reference and illustrative purposes to explain the effect ! the net imbalance force vector F; on the drill bit 22 and curve drilling assembly 20. For example and with reference to the drawings, force plans P~ lies in the plane of the drawing sheet of Fig.. 3 and extends outwardly from longitudinal bit axis 31 through the bearing means 48. When the drill bit 22 is viewed longitudinally as shown in Fig. 4, plane P~emerges perpendicularly from the drawing sheet with its projection corresponding to net imbalance force vector F;. Force plans P~ is important in understanding the effect of the net imbalance force vector F;
because net imbalance force vector F; may not always intersect gauge portion 40. In some instances, for exempla, forco vector F; may extend outward radially from bit axis 31 at or near face portion 42 directly toward the borehola wall without passing through gauge portion 40. Even in these instances, however, the net imbalance force identified by force vector F; will be directed and lie in a radial plane P~ of the drill bit 22 which passes through the gauge portion 40.
Referring to Pigs. 5 and 6, the preferred cutting element devoid region 60 extends the full longitudinal or axial length of gauge portion 40, and preferably further extends onto face portion 4Z along the ciscoetesential and axial dimensions. Cutting element devoid rsgio~t 60 say extend circumferentially along, or around, substantially all o! the ciscumferencs of the gauge portion so ("gauge circuaelsrsncs"), such as, for example, in a drill bit having only one cutting element on the gauge portion. For most applications, the cutting element devoid region will extend around ~'a bout 20~ to 70~ of the gauge circumference. Cutting a n ~'~dekvoid region 60 preferably extends axially from the line 54 between the gauge portion 40 and the face portion 42 at least one-third of the distance to the intersection of the bit axis 31 with face portion 42. Selected ones of cutting elements 44, 56 may be positioned adjacent to cutting element devoid region 60 to increase the number of cutters on the drill bit and thereby improve its cutting efficiency.
The bearing means 48 is disposed in the cutting element devoid region 60 about the force plane P; for substantially continuously contacting the borehols wall 28 during the drilling. The bearing means may comprise one or mars rollers, ball bearings, or other low friction load bearing surfaces. Preferably, the bearing means 48 comprises a substantially smooth, wear-resistant sliding surface 48 disposed in the cutting element devoid region 60 about the force plane P~ for slidably contacting the borehole wall 28 during the drilling. The preferred sliding surface 48 intersects the force plane P~ formed by the longitudinal bit axis 31 and the net imbalance force vsGtor F;.
Sliding surface 48 constitutes a substantially continuous region that has a sit. equal to or smaller than cutting element devoid region 60. Sliding surface 48 is disposed on gauge portion 40. Sliding a~urtace 48 may comprise the same material as other portions of drill bit 22, or a relatively harder material such as a carbide material. In addition, sliding surface 48 may include a wear-resistant coating or diamond impregnation, a plurality of 'amond stud inserts, a plurality of thin diamond pads, or similar inserts or impregnation that strengthen sliding surface 48 and improve its~durability.
Sliding surface 48 directly contacts the borehols wall 28.
Drilling mud is pumped through the drill bit and circulates up the borshole past the gauge portion of the drill bit thereby providing some lubrication far sliding surface 28. Significant contact of the sliding surface with the borehols wall doss occur. Accordingly, low friction, wear-resistant coatings fox the sliding surface 48, as discussed above, are often desirable.
The specific size and configuration of sliding surface 48 will depend on the specific drill bit design and application.
Preferably, the sliding surface 48 extends along substantially the entire longitudinal length of gauge portion 40 and extends circumterentially around no more than approximately 50% of the gauge circumference. The sliding surface may extend around about 20% to 50% of the gauge circumference. Preferably, the sliding surface, or bearing means, 48 extends around a minimum of about 30%
of the gauge circuaterence.
The preferred sliding surface 48 is of sufficient surface area so that, as the sliding surface is forced against the borehole wall 28, the applied force will be significantly less than the compressive strength o! the subterranean earthen materials of the borehole wall. This keeps the sliding surface 48 from digging into and crushing the borehole wall, which would result in the creation of an undesired bit whirling motion and overgauging of the borehole ''6. Sliding surface 48 also has a size sufficient to encompass net imbalance force vector F; as force vector F; moves in response to a change in hardness of the subterranean earthen materials and to other disturbing forces. Preferably, the size of the sliding surface 48 is also selected so that the net imbalance force vector F; remains encompassed by the sliding surface as the bit wears.
Sliding sumacs 48 is preferably positioned at a radial distance from the bit axis 31 that is substantially equal to the gauge radius R~, i.e., the sliding surface 48 and gauge cutters) 56 define the gauge radius R~ of the drill bit 22 as well as the diameter of the gauge portion 40 of the drill bit 22. Sliding surface 48 may comprise a continuous surface of hardened, wear-resistant material on the gauge portion 40 of the drill bit 22.
Preferably, the sliding surface comprises a plurality of spaced sliding surfaces 48, as shown in Figs. 3-6. This facilitates hydraulic flow around the drill bit 22 which improves drilling efficiency and promotes cooling of the bit. This design is preferred for certain drilling applications.
2.3 ~s Force Keens Retersfng- to thf example of Figs. l, 3 and 4, the curve drilling asseably 20 includes imbalance force means 46 for creating a net fabalanc~ tosc~ along a net imbalance force vector F, substantially perpendicular to the longitudinal bit axis 31 during drilling. This subsection firstly gives an overview of the preferred components and properties of the imbalance force means ~~U_~.Ci~~.~
'b, secondly discusses the various forces acting on a drill bit during drilling and how they are created, and thirdly discusses how the forces are controlled to produce the imbalance force means 46 and curve drilling assembly 20 of the present invention.
The imbalance force means 46 may include a mass imbalance in the drill bit 22 or drill string 24, an eccentric sleeve or collar placed around the drill bit 22 or drill string 24, or similar mechanism capable o! creating the imbalance force vector F; (not illustrated). Preferably, the imbalance force means includes a radial imbalance force and the cutting elements 44, 56 are disposed for creating the radial imbalance force along a radial imbalance force vector F,, (Fig. 8) during drilling. Further in accordance with the invention, the imbalance loran means 46 includes a circumlerential imbalance force and the cutting elements 44, 56 are disposed !or creating the circumferential imbalance force along a circumterential imbalance force vector F~i (Fig. 8) during drilling.
Further in accordance with the invention, the net imbalance force vector F, is a coabination or resultant of the radial imbalance force vector 1~,, and the circumferential imbalance force vector F~,.
The magnitude and direction o! net imbalance force vector F, will depend on. the positioning and orientation o! the cutting elements ~~,~56'; e.g., the specific arrangement o! cutting elements 44, 56 on d=ill bit 22, and the shape o! the drill bit 22 since the shape influences positioning of the cutting elements 44, sb.
Orientation includes backrake and siderake of the cutting elemen t 44, 56. The magnitude and direction of force vector F; is also ~~3~.ci~ 4 'nlluencad by a number of factors, such as the specific design (shape, size, etc.) of the individual cutting elements 44, 56, the weight-on-bit load applied to the drill bit 22, the speed of rotation, and the physical properties of the subterranean material being drilled.
Further in accordance with the invention, the cutting elements 44, 56 are disposed to cause net imbalance force vector F; to substantially maintain the bearing means 4S in contact with the borahole wall during the drilling, to Gauss net radial imbalance force vector Fj to have an equilibrium direction, and to cause net radial imbalance force vector F; to return substantially to the equilibrium direction in response to a disturbing displacement.
These aspects o! the invention and the related forces on the drill bit will also be discussed in greater detail below.
The principal forces acting on a subterranean drill bit as it drills through subterranean earthen materials include a drilling torque, the weight-on-bit, a radial imbalance force, a circumterential imbalance force, and a radial restoring force. with reference to Fig. 7, the weight-on-bit (woe) is a longitudinal or axial force applied by the rotational drive source (drill string) that is directed toward the face portion 42 of the bit 22.
Subterranean! d=ill bite are often subject to weight-on-bit loads of 10,000 lbs. os sore.
The radial imbalance force is the radial component o~' the force created on the drill bit 22 when the bit is loaded in the axial direction. The radial imbalance force can be represented as ~~.~~~r~u radial imbalance force vector F,;, exemplified in Fig. 8, which is perpendicular to the longitudinal bit axis 31 and intersects with a longitudinal projection of the gauge circumference at a point R, as shown in Fig. 8. The radial imbalance force vector F,; and longitudinal bit axis 31 also define a radial force glane which extends radially from bit axis 31 through point R. The magnitude and direction of force vector F,; is independent of the speed of rotation of the bit, and instead is a function of the shape of the drill bit; the location, orientation, and shape of the cutting elements; the physical properties of the subsurface tormati~on being drilled; and the weight-on-bit. The location, orientation, and shape of the cutters, however, usually are the factors most amenable to control. If the drill bit and its cutting elements are perfectly symmetrical about the longitudinal bit axis and it the weight on the bit is applied directly along the bit axis, then the radial imbalance force F,; will be zero. However, in the preferred embodiment, the drill bit and cutting elements era shaped and positioned so that a non-zero force F,; is applied to the drill bit when the bit is axially loaded. The force F,; can be substantial, up to thousands of pounds.
Ths cireuatsrltltial imbalance force is the net radial component obtained by vectorially summing the forces attributable to the interaction o! the drill bit, primarily the individual cutting elements, with the borehole bottom and walls as the bit rotates. This circumferential imbalance force can be represented as a circumferential imbalance force vector F~; (as exemplified in Figs. 8 and 9) whie:h is perpendicular to the longitudinal bit axis 31 and intersects with a longitudinal projection of the gauge circumfarancm at point C. The circumferential imbalance force vector Fd and longitudinal bit axis 31 also define a radial force plane which extends radially from bit axis 31 through point C. As explained below, the magnitude of the circumferential imbalance force vector Fd can vary, depending upon both the design of the drill bit (shape of the bit and shape and positioning of cutting elements), the operation of the drill bit, and the earthen materials being drilled.
For example, Fig. 9 shows a longitudinal view of a drill bit 22 having cutting elements 44a, 44b which era symmetrically disposed on the face portion 42 of the drill bit 22 with respect to one another. If such a bit rotates about the bit axis 31, and if cutting elements 44a, 44b cut a homogeneous material so they experience symmetric forces, the respective cutting elements will create a force couple o! torque with zero net force directed away from the bit axis 31. It, however, cutting elements 44a, 44b are not perfectly symmetric, or if they cut heterogeneous material so they experience different or asymmetric forces, the respective cutting eleaents 44a, 44b will create both a torque about a center of rotatioi! displaced trots the bit axis 31 and a non-zero net circumtsrential iabalanca force F~ directed in a radial plane towards the point C on the projection of the bit. Subterranean drill bits usually create a non-zero circumfarantial imbalance force F~;. As will be explained in greater detail below, the present ~~~~.8~~i tnvantion includes a drill bit that is intentionally designed to create a substantial circumferentiai imbalance force F«.
Referring to Fig. 8, the circumferential imbalance force vector Fd and the radial imbalance force vector F,; combine to create the net imbalance force vector F;, which is substantially perpendicular to the longitudinal bit axis and which intersects with a longitudinal projection of the gauge circumference at a point N. Ths imbalance force vector F; and longitudinal bit axis 31 define force plans P~ which extends radially from bit axis 31 through point N. This force point N indicates the point or region on a projection of the gauge circumfarencs corresponding to the portion of the drill bit 22 that contacts the borahola wall in responses to the net imbalance force vector F; at a given time. Divan the gaometries of the drill bit and the borehole wall, the gauge portion o! the drill bit will contact the borehola wall. The bearing means is disposed on the drill bit at a location that generally corresponds to this contacting portion of the drill bit to provide the radial restoring force required to balance force vector F,.
An appreciation of the invention is further facilitated by an understanding o! the concepts of static and dynamic stability as they apply to the drill bit of the present invention. Statically stable bit rotatiotf, as the term is used in this document, can be defined as a condition in which the center of rotation of the drill bit stays at a fixed point on the drill bit surface in the absence of a disturbing force or a formation heterogeneity. For example, 2~,~~:~.~~
~'ig~. 10 shows a drill bit 22 with a longitudinal bit axis 31. Drill bit 22 rotates in a borehole 26 having a cylindrical borehole wall 28. Ths canter, or longitudinal axis, of borehols 26 is designated by reference numeral 70. Because drill bit 22 rotates about a fixed center of rotation on the bit surface, i.s., longitudinal bit axis 31, the rotation is statically stable. A condition in which drill bit 22 is rotated about a fixed point on the drill bit surface, but in which this center of rotation on the drill bit is not co-located with bit axis 3~., would also bs considered statically stable rotation. Statically stable bit rotation is usually accompanied by a net imbalance force vector F; that has a substantially constant magnitude and direction relative to the drill bit. The direction of this constant force vector F; can bs considered an equilibrium direction.
Dynamic stability, as the term is used in relation to low friction subterranean drill bits of the invention, refers to a condition in which the net imbalance torts vector F; returns to an equilibriwa direction in response to a disturbing displacement. The disturbing displacsasnt may be caused by a number of factors, such as the encountering of a change in subterranean earthen material hardness, the o!! axis aovemsnt of the drill bit itself, and drill string vibrstions.
A subtsrranaan drill bit rosy have static stability, i.e., net imbalance torts vector F, may bs directed to an equilibriu~s direction, but fail to have dynamic stability, i.s., a disturbing displacement will move forts vector F; away frog the squilibri~~

~~t~.,~~~'ui~
direction and force vector F; will not return to the equilibrium direction upon relaxation, as explained in greater detail below.
Throught an extensive research effort, the assignee of this application has discovered that cutter damage and corresponding drill bit failure apparently are caused by impact damage attributable to a subterranean drilling phenomenon termed backward whirl. Backward whirl is defined as a statically and dynamically unstable condition in which the center of rotation of the drill bit moves on the bit surface as the bit rotates. A more complete l0 description of the backward whirl theory is provided in J.F. Brett, T.M. Warren, and S.M. Behr, ~~Bit Whirl: A New Theory of PI~C Bit Failure,n Sociatv of Petro~p~m Fnc~ nppxa, (SpE) 19571, presented at the 54th Annual Technical Conference of the SPE, San Antonio, Texas, October 8-11, 1989. The phenomenon of backward whirl can be explained with relarence to Fig. 11.
Fig. 11 illustrates a condition in which drill bit 22 has been moved by net imbalance torce F; radially in the borehole to a position in which the drill bit contacts borehols wall 28 at a contact point 7Z adjacent to force point N. It the net imbalance force vector P~ bscoses large enough to force the surface of the bit against the borehole stall, and it frictional or cutting forces prevent thf drill bit outface contacting the borehole wall 28 from sliding on tl~. borehole wall 28, contact point 72 becomes the instantaneous center of rotation for the drill bit. For example, the instantaneous center of rotation of the drill bit may move from the longitudinal bit axis 31 toward contact point 72. The frictional force between the drill bit surface and the borehole wall 28, which is caused or accentuated in conventional subterranean drill bits by the gauge cutting elements around the gauge portion o! the bit, causes the instantaneous center o!
rotation of the bit to continue to move around the face portion of the bit, away from the longitudinal bit axis 31 and toward the borehole wall, as the bit rotates.
When a drill bit begins to backward whirl, the cutting elements can move backwards, sideways, etc. They move farther per revolution than those on a bit in stable rotation, and they move faster. As a result, the cutters are subjected to high impact loads when the drill bit img~acts the borehole wall, which occurs several times per bit revolution for a whirling bit. These impact forces chip and break the cutters. once backward whirl begins, it regenerates itself. The inventors discovered that backward whirl in an overgaugsd borsholo allows the curve drilling assembly to deviate from the structural configuration required to drill a curved bvrehols having a reliable, predictable radius o! curvature, i.e., the backward whirl and the overgauged borehole allow the drill bit and curved drilling assembly to become sufficiently misalignsd in the borshols to prevent the reliable drilling of a curved borshols.
Tha present invention is designed to overcome the problems caused by ovsrgauging and by backward whirl o! a subterranean dri 11 bit in a cures drilling assembly. The subterranean drill bit 22 of the present invention overcomes the undesirable effects of backward 'girl by providing a cutting element arrangement and corresponding drill bit profile that, during the drilling, direct the net imbalance force vector F; towards the bearing means 48 and substantially maintain the force vector F; on the bearing means in 3 a stable fashion. The bearing means provides a low friction contact with the borehole wall. Ths cutting element devoid region 60 also minimizes frictional forces, such as those attributable to gauge cutting~elemsnts, from causing the drill bit to grip or dig into the borehola wall and move the instantaneous canter of rotation of the drill bit.
In accordance with the invention, the cutting elements 44, 56 are disposed to cause the net imbalance force vector F; to have a magnitude and direction which will substantially maintain the bearing means in contact with the borehols wall during the drilling, and which will avoid creating frictional or cutting lorces that will cause the drill bit to grip or dig into the borehols wall and move the instantaneous center a! rotation of the drill bit on the bit. Ideally, this condition would hold throughout the operation of the drill bit. Further in accordance with the invention the cutting elements era disposed to cause the net imbalance foscs vscto= P, to have an equilibrium direction. The features of the invention in which the cutting elements are disposed t0 causm the net imbalance force vector to have a magnitude and direction to substantially maintain the bearing means in contact with the borehole wall during the drilling, and to cause the net radial imbalance force vector to have an equilibrium 2~~18~
~iiraction, are related to the static stability of the drill bit.
The drill bit o! the present invention is preferably designed so that force point N, fox assumed steady state conditions, is located at a point in the leading portion or half of the bearing means 48. This relationship is illustrated by Fig. 12, which shows a leading hal! 48a and a trailing half 48b of sliding surface 48, with the bit rotating counter-clockwise as indicated by the arrow.
With this arrangement, if the drill bit 22 encounters harder earthen materials or "hangs up" for a moment on the borehole wall, the variable force vector F~; will not mave net imbalance force vector F; rearward beyond the trailing hal! 48b o! sliding surface 48. Because force vector F~; is more variable than F,;, in the preferred embodiments, force vector F,; for steady state conditions is greater than force vector F~;. This relationship enhances the static and dynamic stability o! the drill bit.
The magnitude o! the net imbalance force vector F; preferably is in the range o! about 3; to 40~ o! the applied weight-on-bit load. For example, i! the weight-on-bit load is 10, 00o pounds, then F, should be within the range of 300 to 4,000 pounds. I! the drill bit is designed !or relatively low weight-on-bit, the force vector F; should b~~reIatiwly large and vice versa. It the drill bit is designed lo~C relatively high RPM, a somewhat greater force vector F; is need. I! a relatively large drill bit is used, the force vector F; should be decreased. of course, the greater the magnitude 0! force vector F;, in general, the greater will be the wear on the bearing means 48.
J

~~S~.~fl The drill bit of the invention can bs further refined by specifically positioning the cutting elements (including selecting the drill bit shape and design) not only to control the direction and magnitude of net imbalance force vector F;, but also of the individual force components making up the force vector F;, i.e., circumtarential imbalance force vector Fd and radial imbalance force vector F,;. More apacifically, drill bit performance has shown improvement by positioning the cutting elements 44, 56 so that at least one of force vectors Fs; and F,; is directed towards the bearing IO means 48 at all times during the operation of the bit. Additional stability can be achieved by designing the drill bit shape and positioning the cutting elements so that force vectors F,; and F,; are approximately aligned with each other and with the resultant net imbalance force vector F;.
Further in accordance with the invention, the cutting elements are disposed to cause net imbalance force vector I~; to substantially return to the equilibrium position in response to a disturbing displacement, grsterably !or disturbing displacements or offsets of up to 75 thousandths o! an inch. This faatura o! the invention is related to the dynasic stability o! the drill bit.
The aag~fitudt and direction of net imbalance force vector F, !or an operational subterranean drill bit will change as the bit operates. TDis moveaent may ba caused by the factors above, such as heterogeneity o! the subterranean earthen materials to ba drilled.
The lack o! dynamic stability can cause forco vector F; to move away from the bearing means in response to a disturbance, and eitne~

~onvsrgo to a now esquilibrium position away from the bearing means ar become dynasically unstable, in which case force vector F; can continua to grove as further drilling occurs.
The drill bit of the invention pravides dynamic stability by making sliding surface 48 of sufficient size to encompass the net imbalance force vector F;, or force plans P~, as the net imbalance force vector Fi moves in response to changes in hardness of the subterranean earthen materials; and by positioning the cutting elements to minimize the variations in the direction of force vector Fi. If the sliding surface, or bearing means, 48 is not sufficiently large to create this condition, backward whirling and ovorgauging can occur. Through experimentation, the inventors have found that the sliding surface preferably should extend over at least 209, and up to 509, of the gauge circumference. As a general rule of thumb the circumforential length, or extent, of the sliding surface around the gauge circumference should correspond to the expected tango of movement o! force vector F" plus up to about 20%
on either side o! this range of movement.
Ths inventors have discovered that overgauging of the borehole is further reduced and performance of the cusvs drilling assembly 20 is furtbst iaprowd by placing the gauge cutting elements 56 on the gauge postion of the drill bit 22 so that a radial plane P,~ of the drill bit Mending through the gauge cutting elements defines an angle J~, of at least 90 degrees and not more than 270 degrees with the force plane P~. Referring to the exampl. of Fig. 13, the angle ~, should bo measured from the gauge cutting element 56 ~~8~8(~
closest to the force plane Pf. Placing the gauge cutting elements ,_ more than 94 degrees and less than 270 degrees from the force plane P~ removes components of the net imbalance force vector F; from the gauge cutting elements 56 which force the gauge cutting elements into the borehole wall 28 and thus reduces overgauging. Preferably, the angle Aa is about 180 degrees and the gauge cutting elements) 56 is disposed on the gauge portion 40 of the drill bit 22 substantially opposite to the intersection of the forc~ plane Pf with the bearing means, or sliding surface, 48 in order to maximize tho component of the force vector r; acting on the gauge cutting elements 56 which biases the gauge cutting elements 56 away from the borehols wall 28.
Referring to the example of Fig. 12, the imbalance force vector F;, and therefore the force plane P~, move circumferentially with respect to the gauge portion 40 of the drill bit 22 in response to a disturbance of the curve drilling assembly during drilling. In further accordance with a preferred embodiment of the invention, exemplified in Fig. 12, the cutting elements 44, 56 are disposed for causing the force plane P~ to remain within a force plane arc 74 on the circumference of the gauge portion 40. The force plans era 74 ~eay bs visualized as having radial boundaries 74a, 74b at sack ciscuafsrential end of the arc 74. Preferably, the gauge cutting olsaants 56 are located within a gauge cutting arc ~ 6 on the gauge portion. The gauge cutting arc 76 may bs visualized as having radial boundaries 76a, 76b at each circumferantial end of the arc ?6. Ths angle J~, between adjacent boundaries 74a, 76a; 74b, 2~~~.~~
~6b of the arcs 74, 76 is preferably greater than 90 degrees and less than Z70 degrees in order to remove components of the net imbalance force vactos F; from the gauge cutting elements 56, and from the gauge cutting arc 76, which would force the gauge cutting elements into the borehole wail 28. More preferably, the gauge cutting arc 76 is located on the gauge portion substantially diametrically opposite to the force plane arc 74. Further, the cutting~alamants 44, 56 are preferably selected and arranged so that the force plane arc 74 is encompassed within the bearing l0 means, or sliding surface, 48 in order to maximize the static and dynamic stability of the drill bit 22 in accordance with the preceding teachings of this document.
Further in accordance with the invention, referring to Figs.
14 and 15, the sliding surface, or bearing means 48, may be disposed for forcing the gauge cutting alement(s) 56 into cutting engagement with the boraholo wall 28 when the gauge cutting element 56 is about axially coincident with the inside radius R, of the curved borahole 26, as exemplified in Fig. 14, in order to enhance the ability of the assembly 20 to create the curved borehole.
Preferably, the sliding surface 48 is located on the gauge portion 40 of the ds*lI bit =~.about opposite the gauge cutting element 56, i.a., on thm di~trically opposite side of the gauge portion 40, as illustrated i~ Figs. 14 and 15. The sliding surface 4s is constructed, arranged, and shaped to utilize the straw or angle oe the bit axis 31 with respect to the borehole axis 70 and to laterally displaee or move the drill bit 22 and gauge cutting 2~~~~~~
element 56 into deeper cutting engagement with the borehole wall when the gauge cutting element is about axially coincident with the inside radius Ri of the curved borehole 26 than will the skew of the bit axis alone. By moving the cutting elements 56 into deeper, penetrating engagement with the inside radius R~ of the borehole 26, the drill bit 22 slightly overcuts the inside radius which causes the drill bit and mssembly 20 to move toward the inside radius and thereby enhances the creation of the curved borehole 26.
As exemplified in Figs. 14 and 15, the invention further provides a cutting element devoid cutter pad 80 which may be located on the gauge portion 40 of the drill bit 22 between the gauge cutting elements) 56 and the base portion 36 of the bit.
Preferably, the cutter pad 80 extends radially from the drill bit a lesser distance than the gauge cutting element 56 so that the gauge cutting element 56 cuts the borehola wall 28 and the cutter pad 80 does not: The cutter pad 80 is constructed, arranged, and shaped to cooperate with the sliding surface 48 in using the skew of the bit axis 31 to sove or bias the gauge cutting elements into laterally peinetrating engagement with the inside radius R, of the borehole 26 and to rssow the laterally penetrating bias when the gauge cutting eleaa~tts 56 are not adjacent the inside radius. The cutter pad S0 say ha ah integral feature of the gauge portion 40 of the drill bit ~~, that is, the gauge portion 40 of the drill bit 22 may be shaped or forced and the radial extension of the gauge cutting elements 56 fros the gauge portion 40 adjusted to provide the functions of the cutter pad described herein. In the embodiment '\ /~ 'j'!
2~~ c3~u ~t Figa. 14 and 15, the cutter pad 80 is a hardened pad which is added to the gauge portion 40.
The preferred sliding surface 48 has an uphole end 82 adjacent the bass portion 36 of the drill bit and a downhole end 84 adjacent the face portion 42 of the drill bit. Preferably the gauge cutting element 56 is located nearer to the face portion 42 than is the downhola end 84 of the sliding surface 48 so that gauge cutting element 56 cuts the borehola wall and the sliding surface 48 does not. Ths downhole end of the sliding surlace should be farther from the face portion 42 than the downhole edge o! every gauge cutting element 56. It is preferred that the sliding surface 48 and cutter pad 80 be constructed and arranged to avoid creating any edges or surfaces which cmn cut or dig into the borehole wall 28 and thereby overgauge the borehols 26 and precipitate backward whirl of the drill bit 22. The sliding surface 48 and the cutter pad 80 are preferably about the game shape in the circumtersntial dimension as the bit gauge portion 40 upon which they are respectively located.
The sliding surlace 48 and the cutter pad 80 may be shaped in the axial or longitudinal dimension to match or align with the radius of curvature o! the curved borehole 26.
The iabalsncl force vector F;, or force plans P~, is preferably directed tArouQl~ tho sliding surface, or bearing means, 48 within force plsne2 era 74 (lig. 12) approximately opposite to the gauge cutting eleaent(s) s6, as illustrated in Figs. 14 and is.
Z5 Therelose, referring to Fig. 14, when the gauge cutting element 5e passes across the tap or inside radius R, of the borehole, the nec 2~~~~.~~
'mbalance force vector F, is directed to force sliding surface 48 against thetoutaide radius Ro of the borehole 26; and the preferred sliding surface 48 is constructed and arranged to support the drill bit: 22 and to cooperate with the skewed axis 31 of the drill bit 22 in moving, or laterally displacing, the gauge cutting element 56 into engagement with the inside radius R, of the borehole 26. At the same instant, there era no gauge cutting elements 56 in force plane P~ on the sliding surface 48 to cut the outside radius F~ of the borehole.
As the drill bit 22 is ratated sa that the gauge cutting elemant(sj 56 (or cutting arc 76) is not adjacent the inside radius R, of the borshola 26 (and not on the inside radius of the angle of the bit axis 31 with the borehole axis 70j, the preferred sliding surface 28 cooperates with the angle of the bit axis 31 to remove the displacement which biases the gauge cutting element 56 into penetrating engagement with the inside radius R,. This !unction and property is most pronounced when the gauge cutting element 56 is adjacent the outside radius Rp of the borehole. Referring to Fig.
15, when the drill bit 2Z is rotated so that the gauge cutting element 56 is adjacent the outside radius E~, of the borehola 26, the force plant Pt ~! net iabalance force F, will be directed through the slidinef sustaCt 48 which will be adjacent to the inside radius R, of the bo~tehole Z6. Since the net imbalance force F, is preferably much greeter in magnitude than the weight of the curve drilling asseably 20, the net imbalance torte Fi biases the drill bit 22 away troa the outside radius of the borahols 26 and thereby inimizes cutting on the outside radius Ro of the borehole 26. In the preferred embodiment of Figs. 14 and 15, when the gauge cutting element(sj 56 is not adjacent the inside radius R;, there should be no lateral forces acting on the gauge cutting element 56 to force it towards the borehole wall 28 and therefore the gauge cutting element 56 should cut the gauge radius R~ and cut a substantially gauge borehole as it is rotated around the portions of the borehole other than the inside radius R;.
In the curve drilling assembly of the present invention, the imbalance force means 46, bearing means or sliding surface 48, and gauge cutting elements) 56 cooperate to remove components o! the imbalance force vecto~c F; from the gauge cutting elements 56 which would radially or laterally force the gauge cutting elements 56 into the borehole wall 28; to laterally displace the gauge cutting elements into penetrating engagement with the borehole wall 28 when the gauge cutting elements 56 are adjacent the inside radius R; of the borehole; and to remove the lateral displacement when the gauge cutting elements 56 are not adjacent the inside radius Ri. Rather than using a reamer as a fulcrum to leverage the drill hit against the inside radius of the curved borehole 26, the present invention guides or points tho drill bit 22 in the desired direction; uses the relative positioning of the cutting elements 44, 56 and the net imbalance tosce F~ to control gauge cutting, reduce ovargauging, and to enhance the ability of the assembly 20 to drill a curved borehole; and uses the net imbalance force F; and sliding surface 48 to noncuttingly transfer the lateral forces in the drill bit to 2~~:~.~0~
'he borehols wall, effectively using the borehole wall 28 as a bearing surface for the gauge portion 42 of the drill bit 22.
If a drill bit in accordance with the present invention is operated at high rotational speed, e.g., of 500 rpm or more, the 3 net imbalance force vector Fi will have a significant dynamic component associated with centrifugal forces. In such an . embodiment, the magnitude of force vector Fi can be increased by constructing the drill bit so that a portion of the cutting element devoid region has a first density and portions of the drill bit other than the cutting element devoid region have a second density different from the first density. A similar result may be achieved by constructing the drill bit so that the bearing means has a first density, and portions of the drill bit other than the bearing means have a second density different from the second density.
Preferably, such a drill bit can be designed to have a greater mass on its side adjacent the bearing means, so that centrifugal forces push the bearing means against the borehole wall. The asymmetric mass distribution in a rotating body creates a force that can contribute to the net imbalance force.
2 0 3 . 0 ~'j,~$~',~jQ~,~Q~
In thisu8eatioa, the curve guide means 34 and contact means 50 are described as controlling the deflection and the forces created near the deflection 30. The curve guide means 34 is discussed in subsection 3.1 and the contact means 50 is discussed in subsection 3.2.

~.1 Curve ~uidm Means. Borehole .naacrfn Meang,, and Housinc Features.
In ordear to drill a curved borehole 26, it is necessary to initiate and maintain a dellection 30 of the drill bit axis 31 with respect to the longitudinal axis 70 of the borehole 26 and to control the azimuths! direction of the dellection in the borehole 26. Referring to the example o! Figs. 1 and 16, the invention includes curve guide means 34 for initiating and maintaining deflection 30 by deflecting the drill string 24 toward the borehole wall 28.
In accordance with the invention, referring to the examgle of Figs. 16 and 17J~, the curve guide means 34 includes a mandrel 86 rotatably disposed within a housing 98. The mandrel 86 includes an uphole and 88, a downhole end 90, longitudinal or rotational axis 92, and a !laid passageway 94. The housing 98 includes an uphole end 100, a downhole end io2, longitudinal axis 104, and a passageway 106 extending through the uphole and downhole ends io0, 102. The passageway 106 may extend through the housing at an angle skewed with respect to the housing axis 104 in order to~skew the rotational axis o! the mandrel 86 with respect to the housing axis I04.
The housing includes borehole engaging means 108 for preventing rotation o! the housing 98 with the mandrel 86 during drilling. The boretsole engaging means 108 may ba any type of spikes, blades, wire-like or brush-like members, or other friction creating devices which will engage with the borehole wall 28 to ~~3 ~rewent rotation o! the housing 98 when the drill bit 22, drill string 24, and mandrel 8C are rotated during drilling (normally in a clockwise direction viewed from the top of the borehole 26) and which will permit rotation of the housing 98 with the mandrel 86 when the mandrel is rotated in the opposite direction (normally counterclockwise). Referring to the example o! Fig. 17A, preferably, the borehole engaging means 108 are a plurality of blades 108 which are spaced apart around the circumference of the housing 98 and which extend axially along the housing 98.
Prefermbly, the blades 108 are biased into engagement with the borahole wall 28 with springs 110.
Fig. 1'7H illustrates an alternative embodiment o! the borehole engaging means 10i, in which one of the spring loaded blades 108 is replaced with s fixed blade 112. Tha fixed blade 112 has a sharp axially extending edge 114 which, together with the housing 98, defines a diameter slightly larger than the expected diameter of the borehole 26. The axial edge 114 scores the borehole wall 28 and assists in pseventing the housing 98 from rotating with the mandrel 86 in order to maintain the rotational orientation o! the assembly 20 in the borehole Z6. When the fixed blade 114 is used, the housing 9S say bs aoved into a portion of the borehole having a diameter largos thaArths diameter defined by the fixed blade 11a when it is de~iss~d.to.sotate the housing 98 with the mandrel s6.
The bosehole engaging means 108, including the spring loaded blades 108 and the fixed blade ii2, may bs placed at virtually any location around the circuaference of the housing 98, although they ~

re, preferably placed so that they do not bear the weight-on-bit and do not transfer the weight-on-bit to the housing 98, for reasonw that are further discussed below. The distance which the borehole engaging means 108, particularly the fixed blade 114, extends radially from the housing 98 and the longitudinal shape of the outermost surface of the borehole engaging means 108 may be selected to assist in guiding the curve drilling assembly, e.g., the portion of the borehole engaging means 108 which contacts the borehale wall 28 may be shaped or curved to conform to the desired curvature of the borehole.
Alternative embodiments of the borehole engaging means 108 include sizing the outside diameter of the housing 98 so that it is slightly less than the expected borehole diameter, and passing the mandrel 86 through the housing 98 at a sufficient angle, or skew, with respect to the housing axis 104 that the eccentricity of the housing 98 with respect to the rotational axis 9Z of the mandrel es will cause the housing 98 to contact the borehole wall 28 if the housing tries to rotate. Such a contact may be designed to prevent the housing 98 Eros rotating with tho mandrel 86. In such an embodiment the drill bit should be loaded, i.e., weight-on-bit should be placeel, before beginning drilling to ensure that the contact a~eaafo 50 is is contact with the borehole wall 28 and that the rotatio~l axis 9~ of the mandrel 86 is skewed with respect to the borehole axis 70.
Referring to the exaaple of Fig. 17A, the invention further includes sandrel engaging means 116 for rotating the housing ~a So with the mandrel 86 when the mandrel 86 is rotated in an opposite direction to the drilling direction (normally counterclockwise when viewed from the top of the borehole). The mandrel engaging means 116 is provided for rotationally orienting the housing 98 in the borehola 26. Preferably, the mandrel engaging means 116 is a ratchet-type mechanism, one-way clutch-type mechanism, or the like which allows the mandrel 86 to rotate relative to the housing 98 in one direction, but rotates the housing 98 with the mandrel 86 when the mandrel is rotated in the opposite direction. In a preferred embodiment, the mandrel engaging means 116 includes a recess 118 in the mandrel 86 and a pawl 120 activated by spring 122. Tha pawl 120 is connected to the inside surface of the housing 98. Tha recess 118 is shaped and the pawl 120 is positioned by the spring 122 so that the pawl 120 latchingly engages the recess 118 when the mandrel 86 is rotated counterclockwise and so that the pawl 120 does not engage the recess 118 when the mandrel 86 is rotated in a clockwise direction.
Referring to the exempla of Figs. 16, 18, and 19, the housing also includer angle control means 124 for preventing the magnitude of the deflection 30 frog increasing above a predetermined value and dacreaaing balov a predetermined value. The angle control means 124 provides a mschaniam which assists in regulating the radius of curvature og the curved borehole 26. In the preferred embodiment, the angle control means 124 includes an uphole deflector 126 which extends radially from the outside surface near the uphola end 1o0 of the housing 98. The uphole deflector 126 daflectivaly contacts ~~~.a.~ib'~
the borsholt wall 28 in order to create the deflection 30 and to prevent the magnituda>~ of the deflection from decreasing below a predetermine~,valua (and the radius of curdature R~ from increasing above a pradetarainad magnitude). The radial extension of the uphola deflector can ba selected so that the uphola end of the curve guide means 34 and mandrel 86 are deflected a desired minimum amount. The uphola deflector 126 defines the inside radius of the deflection 30, and the instantaneous inside radius Rr of the curved borehola as it is being drilled. As best seen fn Fig. 19, the preferred uphole deflector 126 extends from one side of the housing 98, generally in one radial direction, in order to deflect the housing and drill string 24 in the opposite direction. The uphole deflector 126 may include one or more ribs 126 which define channels 127. Ths channels 127 allow drilling fluid to flow past the uphols deflector 126 and housing 98. The circumferential dimension of the uphole deflector 126 is preferably shaped to confors to the circusfaranca of the borehole 26, as exemplified in Fig. 19.
As extaplifisd in Fig. i8, the preferred angle control means 124 further includes a downhole deflector 128 ~~rhich extends from one side o~ tblr:otitiide surface near the downhole end 102 of the housing 98r-tn-s radial plane or planes about coincident with the uphole detleatot IZS: The downhole deflector 128 should be sized to dsflactively contact the borehole wall 26 in order to prevent the magnitude o! the deflection 3o from increasing above predatarainad value. If the magnitude of deflection 30 becomes too bt ~1 35 ;'"
~~c~~.G~~-~
Treat, the downhole deflector 128 contacts the inside radius R, of the borehole Z6 and prevents further increase in the deflection (and decreass:= in the radius of curvature I~) . This can be an important function when the curve drilling assembly 20 is drilling frc>m a layer o! harder subterranean materials into a softer layer, at which time the curve drilling assembly tends to begin rapidly increasing deflection and decreasing the radius o! curvature of the curved,horahole 26. Under normal curve drilling conditions the preferred downhole deflector 128 does not contact the borehole wall 28. The downhole deflector 128 may include one or more ribs 128 which define channels 1a9. The channels 129 allow drilling fluid to flow pmat the downhole deflector 128 and housing 98.
As exasplitied in Figs. i, 18, and 19, the preferred curve guide means 34 further provides for restricting lateral motion of the housing 98, mandrel 86, and drill bit 22 in the borahole 26 in order to kaep the rotational axis 92 of the mandrel 86 and the longitudinal axis 31 0! the drill bit 2a about coplanar with a plane P, delinsd by the curved borehole during drilling. In the prsterrsd sabodiaont, this feature is provided by sizing laterally extending ribs 133, 134 so that they define a diameter slightly less than that deii~te~l! by the gauge radius ~ o! the drill bit 22.
The ribs:- 1»~ ~, t34. licit the transverse motion o! the assembly 2 0 (with rospeol to- tb~ plane P,) in the borehole and assist the assesbly Z0 in contsolling the azimuthal direction o! the drilling and o! the curved borehole so that the curved borehole 26 remains in a single plane P,.

Referring to the example of Fig. 2, the rotational axis 92 of the mandrel 86 may be skewed with respect to the longitudinal axis 104 of the housing 98. The amount of skew, or the angle, between the mandrel axis 92 and housing axis 104 may be selected, or adjusted, in conjunction with the sizing of the uphole and downhole deflectors 126, 128 to assist in regulating the magnitude of the deflection 30 and the radius of curvature R.~ of the curved borehole drilled by the curve drilling assembly 20.
Referring to the example of Fig. 16, the housing 98 further includes an uphole bushing 136 and a downhole bushing 138. The uphole and downhale bushings 136, 138 are preferably constructed and arranged so that the housing 98 does not contact the mandrel 86 except through the bushings 136, 138 in order to reduce friction and wear. Further, the preferred uphole and downhole bushings are located between the housing and the mandrel at the uphole and downhole ends 100, 102 of the housing 98, respectively, in order to facilitate removal and replacement of the bushings 136, 138, as well as removal and replacement of the housing 98 on the mandrel 86.
The preferred curve drilling assembly 20 also provides an uphole retaining ring 140 connectable to the mandrel 86 at the uphole end 100 of the housing 98 for retaining the housing 98 on the mandrel 86 and a downhole retaining ring 142 connectable to the mandrel 86 at the downhole end 102 of the housing 98 for retaining the housing 98 on the mandrel 86. Preferably, one of the retaining rings 140, 142 is an integral part of the mandrel 86 and the other 2~~~SOj .f .the retaining rings 140, 142 is detachably connectable to the mandrel 86 in order to facilitate removal and replacement of the bushings 136, 138, as well as removal and replacement of the housing 98 on the mandrel 86. In the preferred embodiment of Fig.
16, the uphole retaining ring 140 is threaded for engagement with the uphole end of the mandrel 86. In the preferred embodiment of Fig. 20, the downhole retaining ring 142 is threaded for engagement with the downhole end 90 of the mandrel 86.
In a preferred embodiment of the invention, referring to the example of Fig. 16, the uphole bushing 136 includes a radial flange 144 located between the uphole end 100 of the housing 98 and the uphole retaining ring 140 and an axial flange 146 located between the inside surface of the housing 98 and the mandrel 86. Similarly, the downhole bushing 138 includes a radial flange 148 located between the downhole end 102 of the housing 98 and the downhole retaining ring 142 and an axial flange 150 located between the inside surface of the housing 98 and the mandrel 86. Preferably, the radial flanges 144, 148 are integrally formed with their respective axial flanges 146, 150. The radial flanges 144, 148 bear any thrust or axial loading exerted on the housing 98 by the drill string 24 and mandrel 86 and the axial flanges 146, 148 separate the housing 98 from the mandrel 86 and bear any lateral or radial forces between the mandrel 86 and housing 98. The bushings 136, 138 are press-fit into the housing 98 in the preferred embodiment. The bushings 136, 138 are preferably made of aluminum-bronze or similar low friction, wear resistant materials. Signaling means 152 may be ~~~~v~3 '.nterposed between the uphole or downhole retaining ring 140, 142 and its respective bushing 136, 138.
Referring to the examples of Figs. 16 and 18, the invention further includes signaling means 152 for generating a transmittable signal when the housing 98 is in a preselected rotational orientation with respect to the mandrel 86 in order to monitor the rotational orientation o! the housing 98 in the borehols 26 from the surface o! the earth, or other remote location. According to the invention, the preferred signaling means 152 includes a signal ring 154 detachably connectable to the housing 98 and a signal ring bushing 156 located between the signal ring 154 and the mandrel 86 in order to facilitate rotation of the mandrel 86 relative to the signal ring 154. As best seen in Fig. 18, the signal ring 154~ and bushing 156 circumscribe the mandrel 86. A signal ring port 158 is provided in the signal ring and bushing; and a mandrel port 160 is provided in the mandrel 86. The ports 158, 160 are located so that they are radially coincident at least once during each rotation of the mandrel 86 with respect to the housing 98. As the mandrel 86 rotates within the signal ring 154, a pressure pulse is created each time the ports 158, 160 are aligned, i.s., fluid and pressure are allowed to escape lros the mandrel fluid passageway 94 through the ports is8, 160 into the borehale 26. The escaping fluid creates the pressure pulse which is transmitted through the drilling fluid in the drill string 24 to the surface of the earth where it may be monitored.
By establishing the relative positions o! the angle control means 124, mandrel engaging means 116, and signal ring port 158 on the housing 98, the rotational orientation of the housing 98 and deflection 30 in the borehole 26 may be controlled and monitored.
Since, in the embodiment of Fig. 16, the uphole deflector 126 defines the azimuthal direction of the deflection 30 with respect to the longitudinal axis of the borehole and therefore defines the plans Pb of the curved borehole 26 (as doss the downhols deflector 128 in Fig, 20), the circumferential position of the signal ring port 158 on the housing 98 relative to the uphole deflector 126 (downhole deflector in Fig. 20) is preferably established and fixed. By doing so, the azimuthal direction of the deflection 30 in the borehole 28 may be monitored (after establishing the initial rotational orientation of the uphole deflector in the borehols by wirelins surveying or other known techniques) by monitoring the occurrence o! the pressure pulses. Preferably, the recess 118 and pawl 120 are radially coincident simultaneously with the radial coincidence of ports i58, 160 and a pressure pulse will occur and the accompanying pressure decrease will endure when the recess lla and pawl 120 era engaged to rotate the housing 98 with the mandrel 86 so that the rotational orientation o! the uphole detleetor 126 (downhols datleeto= in Fig. 20) in the borehols 26 may be changed (once it has bash initially established by survey or the like) without requi~c~nng additional surveying. The signaling means may be used to dynaaically monitor the rotational orientation of a housing on a rotating mandrel and the azimuthal direction of a deflection in a drill string created by such a housing, as is described in a i v assignee's U.S. Patent 5,259,4f8 and 5,103,919.
The signal ring 154 may be an integral part of the housing 98.
Preferably, the signal ring is detachably connectable to the housing 98 to facilitate maintenance. It is expected that the signal ring 154 and signal ring bushing 156 will require more maintenance than the remainder of the housing 98. More preferably, the signal ring 154 is detachably connectable to one o! the uphole end 100 (Fig. 20) and downhole end 102 (Fig.l6) o! the housing 98 in order to further facilitate removal and replacement of the signal ring 154 and signal ring bushing 156. In the preferred embodiment of Fig. 16, the signal ring 154 is located between the downhole bushing 138-and the downhole retaining ring 142. The signal ring bu:hing 156 includes a radial flange 16Z to bear thrust loadings betw~et~ the signal ring 154 and the downhole retaining ring 14Z as wll as a~ axial flange 164 to bear radial and lateral loadinga batwet= th~ aandrel 86 and the signal ring 154. The radial flange 14i~ o! the davnhole bushing 138 bears thrust loadings between the signal ring 154 and the housing 98.
In the prototype of the signal ring 154, the signal ring bushing 156 is press fit into the signal ring 154 and then machined ~r~'~.
out to the desired bushing thickness. This construction method is provided to overcome the problems of crinkling and breaking of the bushing material, particularly in the axial flange 164, which occur with attempts to press-fit a bushing of the desired operating thickness directly into the signal rings used with mandrels of smaller diameters, particularly diameters smaller than tour inches.
Preferably, the signal ring bushing 156 is made of the same material as the uphole and downhole bushings 136, 138.
3.2 Contact Means The invention provides contact means 50 which, together with the curve guide means 34, provides for controlling the forces created near the deflection 30.
Referring to the example of Fig. 2, the drill string 24 exerts an axial force F, along an axial force vector during drilling operations. The axial force vector will normally coincide with and extend along the longitudinal axis 32 0! the drill string. The deflection 30 of the drill string 24 creates a longitudinal force component F,, and a radial force component F" of the axial force F,.
Ths longitudinal force component F,, is directed along a longitudinal ford victor which extends along the longitudinal or rotational axis 9Z of the mandrel 86 and the longitudinal bit axis 31. Ths radial force component F"is directed along a radial force vector towards the outside radius Ro of the curved borehole 26. The contact msan~s 50 is provided for contacting the borehols wall 2a and supporting the radial force component F,~ on the borehole wall during drilling. The contact means 50 is preferably locat dHon~ or adjacent and rotatabla with one of the uphole end 88 or downhole end 90 of thr mandrel 8b, as will be further discussed below.
In the preferred embodiment of the invention, referring to the example of Fig. 2, the contact means 50 is a contact ring 50 disposed on and circumscribing the outside surface of one of the uphola and 88 and the downhole 90 of the mandrel 86. Preferably, the contact ring 50 has a substantially smooth wear-resistant sliding surface 176 for slidably contacting the borehole wall 28 during drilling. Tha sliding surface 176 of the contact ring is preferably made o! the same materials as the bearing means sliding surface 48 discussed above. The preferred sliding surface 176 has sufficient surface area that the magnitude of the radial force component P" of the axial force F, acting on the sliding surface 176 is lass than the compressive strength of the subterranean materials of the borahols wall 28 and, therefore, the contact ring 50 does not dig into the borehola wall 28, which would compromise the curve-creating structural configuration of the assembly 20 and avargauga the borahols 26.
As well as supporting the radial force component F" on the borahole wall 2i, ths< contact means 50 ~togsther with the drill bit 22) transles! sll radial and lateral forces craatad in the curve drilling assembly 20 tA the borehole wall 28. The contact means 50 also provides several other important functions. For example, it removes the radial force component F" Eros the housing 98, whim eliminates having a single wear point in the nonrotating housing and allows the housing 98 and bushings 136, 138 to be made of lighter material, which in turn allows the mandrel 86 to be of heavier materials thereby maintaining the structural integrity of the drill string 24~ as the mandrel passes through the housing 98;
it provides a rotating contact with the borehole wall 28 thereby spreading the wear on the relatively moving surface areas of the contact ring 50 and the borehole wall 28; and it provides a contact of fixed position on the assembly 20 to be used in calculating and predetermining the radius of curvature R~ of the curved borehols 26.
By fixing the position of the contact ring 50 on the mssambly, the assembly 20 may be designed and built to drill a curved borehols 26 having a more predictable and constant radius of curvature R,. This may be seen by referring to the example of Fig.
18 and to the following equation:
R~ ~ Li (di ' di) where:
L ~ the distance between the lowermost cutting edge of the lowermost gauge cutter 56 and the uphole end of the sliding surface 176 0! the contact means 50;
dl ~ outside dia~ter of the drill bit 22; and ds ~ olttaid~ disaster of the contact memns 50.
As the equation deaonstrates, the more accurately the distance L
can be defined, the more accurately predictable the radius of curvature o! the borehole will be. Ths equation also demonstrates 2~~3~ ~;~;
that, by varying the dimensions of L, d" and dZ, the radius of curvature can easily and predictably be varied. for example, by mal~ing the outside diameter dz of the contact means 50 larger, the radius of curvature ~ can be increased. Similarly, by increasing or decreasing the distance L, the radius of curvature can be accordingly increased or decreased in direct proportion to the change in the square of the length L.
Tn~ths preferred embodiment, contact means, or ring, 50 is provided at the uphole end 88 of the mandrel 86 for contacting the barehole wall 28 and supporting the radial force component F" of the axial force F, on the borehole wall 28 during drilling.
Preferably, the contact ring 50 is disposed on the outside surface of the uphole retaining ring 140, as exemplified in Fig. 16. In an alternative embodiment, exemplified in Fig. 20, the contact means 50 may be located on the downhole end 90 of the mandrel 86.
Referring to the example of Fig. 2, the deflection 30 of the drill string created by the curve guide means 34 will force the contact maana 50 against the outside radius Ro o! the curved borehole 26 or, it the assembly 20 is being used to initiate a curved borshole 26, the contact means 50 will be forced against the borehole wsli Zs which is diametrically opposite. to the radial extension o! the uphole deflector 128 from the housing 98. The outside dis~stsr c~ o! the contact ring 50 is preferably selected so that the contact ring 50 extends radially frog the outside surface o! the mandrel 86 farther than does the outside surface of the housing 98 adjacent the outside radius Ro o! the curved borehole 26 and so that the assembly 20 has load bearing contact with the borehole wall. 28 at the drill bit 22 and the contact ring 50 but not on the housing 98. By selecting the diameter dz of the contact means 50 so that the housing 98 does not contact the outside radius Ro of the borahola wall 28, the housing 98 does not support the radial force component P" on the borehols wall 28.
Ralerring to the example of Figs. Z6 and 20, the invention includes a spacing member 178 which is detachably connectable between the drill bit 22 and the downhols end 90 of the mandrel 86 for varying the distance between the drill bit 22 and the mandrel downhols end 90 without modifying the drill bit 22 or the mandrel 86 (flexible joint 7.86 in Fig. 20). Ths inventors have found that the simplest method of varying the radius of curvature Ra is to vary the length L and have designed the spacing member 178 for this purpose. The spacing member 178 is designed to ba relatively quickly and inexpensively manufactured in various lengths. This allows thw other cosponents, i.e., the drill bit, contact ring 50, mandrel 8d, tlexible joint 186, etc., which require more expensive and time-consuaing manufacturing processes, to be made in uniform sizes rather than requiring expensive custom manufacturing.

4.0 lllthouq:l the ilwention as previously described may bs used ~ n drilling cus4ad borsholes having long, madiua, and short radii of curvature, it is desirable to modify the drill string near the assembly 20 for drilling a short radius curved borehole, i.e., ~t ~~~~~i~~
~.s desirable to make the drill string 24 near the assembly more flexible in order to enhance the ability of the assembly 20 to drill along a short radius of curvature. ~sShort radius°° of curvature generally refers to a curved borehole having a radius of curvature less than 80 feet.
Referring to the example of Fig. 21, the preferred modifications for drilling a curved borehole having a short radius of curvature include adding a flexible or articulating section 184 of drill string immediately above the curve drilling assembly 20.
The articulating section 184 is preferably comprised o! sections of pipe having articulating joints 185, or the like, as would be known to one skilled in the art in view of the disclosure contained herein. The articulating section 184 is provided so that the drill string 24 does not impair the ability of the assembly 20 to drill a short radius curved borehole, i.e., a conventional drill string often does not have sufficient flexibility to traverse a short radius curved borahola and therefore may not allow the assembly 20 to drill a short radius curved borehola. The articulating section 184 preferably extends uphole from the assembly 20 through the curved portion o! the borehole.
A second modification which further enhances the flexibility of the drill string Z4 and the ability of the invention to drill a short radius. curved borehole is the addition of a flexible joint 186. In the preferred embodiment, the flexible joint 186 is used for connecting the curve guide means 34 with the drill string 2a, i.e., the flexible joint 186 is connectable between the drill 6a .

~~~~ C'3fi.i string 24 and the uphol~ end 88 of the mandrel 8G for flexibly connecting the cures drilling assembly 20 to the drill string 24, as exemplified in Fig. 16. The flexible joint 186 may be a knuckle joint, articulated pipe joint, or other form of universal joint capable of creating the deflection 30 and transmitting torsional, thrust, and tensile forces through the deflection 30. Preferably, an improved flexible joint 186 according to the present invention, as described below, is used.
4.1 First Embodim~
According to a first embodiment of the inventive flexible joint 186, referring to the example of Fig. 22A, the flexible joint 186 includes an about cylindrical ball housing 188 having a toothed end 190 and an about cylindrical socket housing 19Z having a toothed end 194. The toothed ends 190, 194 are shaped to interengags and force an articulating joint (best exemplified in Fig. 2) as well as to transmit the rotation and the torsional forces of the drill string 24 to the drill bit 22. The ball housing 188 includes a ball 196 having a fluid passageway 198. The socket housing 19Z includes a socket 200 for enclosing and capturing the ball 196 and also hae.a fluid passageway 202. The preferred ball and socket 1ls, 100 are constructed and arranged so that the ball and socltst 19i, Z00 and the fluid passageways 198, 20Z are in fluid communicating contact in all drilling positions of the flexible joint 186. The ball and socket 196, 200 transmit the compressive and tensile forces between the drill string 24 and drill bit a2.
r The preferred ball 196, socket 200, and toothed ends 190, 194 are sized so that the ball 196 engages the thrust bearing surface 204 of the socket 200 before the toothed ends 190, 194 make contact when the flexibls joint 186 is subjected to compressive forces, such as the weight-on-bit exerted during drilling. This arrangement is provided so that the flexible joint is flexible under such compressive forces. The inventors have found that, if the toothed ends 190, 194 make thrust transmitting contact, particularly if the portions of the toothed ends 190, 194 on the inside radius of the deflection in the flexible joint 186 males contact before the ball 196 seats against the thrust bearing surface 204, the contact of the toothed ends 190, 194 will tend to straighten out the desired bend or deflection 30 in the flexible joint 186.
Preferably, the thrust bearing surface 204 is formed in a thrust bearing insert 206 which is placed inside the socket housing 192. The thrust bearing insert circumscribes the fluid passageway 202 in the socket housing 192. The socket housing 192 includes a shank 208 for connecting the housing 192 to a drill pips, drill collar, or the like. In the preferred embodiment, the' outside surface of the shank 208 has male threading for engagement with female threading inside the fluid passageway of a drill pipe, mandrel, or the like. The preferred thrust bearing insert 206 includes a llangs 210 which holds the insert 206 in place between the end 212 0! the socket housing shank 208 and a shoulder 214 inside the mandrel 86. Ths preferred socket housing 192 also includsa~ a tensile bearing surface 216 which retains the ball 196 'n the socket 200 when tensile forces exist between the drill string 24 and drill bit 22, such as when the drill string 24, drill bit 22, and assembly 20 are lifted out of a borehole 26.
In the preferred embodiment, the ball 196 is formed on a ball shaft 218 and the ball shaft serves to connect the ball 196 within the ball housing 188 in such a manner that the ball 196 and ball shaft 218 may be removed and replaced, as may the thrust bearing insert 206 and the socket housing 192. The ball shaft 218 includes male threading for engaging the female threading inside the ball housing 188, which may be a drill pipe, drill collar, mandrel, or the like. Ths ball 196, socket 200, and other components of the flexible joint 186 should bs made of materials suitable for the compressive, tensile, torsional, and other forces expected to be exerted by the drill string 24 on the assembly 20 and drill bit 22 during drilling operations, as would bs known to one skilled in the art in view o! the disclosure contained herein.
Further, in the preterred flexible joint 186, the fluid passageway 198, 20Z in the one of the ball 196 and socket 200 to be placed uphole of the other includes a nozzle 220 for accelerating drilling fluid passing through the nozzle 220. Ths fluid passageway 198, 20a in the on1 0! the ball 196 and socket 200 to be placed in the downhol. side o! the flexible joint 186 includes a diffuser 222 for raaovering fluid pressure dropped in the nozzle 220. The nozzle 220 accelerates the fluid before it crosses the gap 224 between the ball 196 and socket 200. Ths accelerated fluid has a lower pressure than the fluid on the exterior of the ball 196 and socket 200 and ~~~3~~;~~ ..
rha pressure differential reduces leakage of the fluid from inside the ball and: socket 196, 200 to the outside. The diffuser 222 decelerats~ the fluid in such a manner as to maximize the recovery of the pressure drop created by the nozzle 220, as would be known to one skilled in the art in view of the disclosure contained herein. The nozzle 220 and diffuser 222 era shaped so that irrecoverable pressure lose across the flexible joint 186 is minimized. Ths shaping and positioning of the nozzle 22o and diffuser 222, as wall as their materials of construction, will be known to one skilled in the art in view of the disclosure contained herein.
Ths flexible joint 186 may be located at either of the uphole and downhols ands of the curve guide matins 34; and is preferably placed at the cams and of the curve guide means 34 sa is the contact means 50. In the preferred embodiment, the contact means 50 is located at the uphole end 88 of the mandrel 86 and the flexible joint 186 is connected between the drill string 24 and the uphol. end 88 of the mandrel 86. Preferably, the socket housing 192 is connected to the uphole end 88 of the mandrel 86 and the socket housing also serves as the uphols retaining ring.l40. The contact msan~ 50 i~ prsterably located on the outside surface o!
the socket hoossing 19~/uphols retaining ring 140 combination.
The outside; surlacs 225 of the toothed end 190 of the ba 11 housing 188 and the outside surface 228 of the toothed end 194 of the socket housing 192 are preferably beveled, or chamfered, as exemplified in Fig. 2211, so that the teeth do not protrude and d~~

2~~~~, fi ~nto the borehole wall 28 when the flexible joint 186 is deflected.
4.2 S~.cond Embodiment In a second, more preferred, embodiment of the flexible joint 186, referring to the example of Fig. 22, the flexible joint 186 may be described as including a loading housing 250 and a socket housing 252. The loading housing 250 includes a first end 254, a second end 256, and a bore 258 extending through the first and second ends 254, 256. The preferred loading housing 250 is about cylindrical in shape and has a longitudinal axis 259 extending through the first and second ends 254, 256. The loading housing 250 also includes at least two loading housing teeth 260 extending from the first end 254 and a loading member 262 disposed in the bore 258 and extending from the first end 254 of the loading housing 250. The preferred loading housing teeth extend about axially from the first end of the loading housing 250. The second end 256 of the loading housing 250 is used for connecting the loading housing 250 into a drill string, drill collar, curve drilling assembly, or the like. Preferably, the bore 258 is in fluid communicating contact with bore 263 of the loading member 262, as exemplified in Fig.~22.
The socket housing 252 includes a first end 264, a second end 266, and a bore 268 extending through the first and second ends 264, 266. The socket housing 252 is constructed and arranged to receive the loading member 262 in the bore 268 at the first end 264 of the socket housing 252. The preferred socket housing 252 is 2fl8~.8fl about cylindrical in shape and has a longitudinal axis 269 extending through the first and second ends 264, 266. The socket housing also includes at least two socket housing teeth 270 extending from the first end 264 of the socket housing 252 for s intermeshing with the loading housing teeth 260 in order to form a flexible cornsction between the loading and socket housings 250, 252 and to transmit rotation and torque between the loading housing 250 and the socket housing 252. The preferred socket housing teeth 270 extend about axially from the first end of the socket housing 252. The second end 266 of the socket housing 252 is used for connecting the socket housing 252 into a drill string, drill collar, curve drilling assembly, or the like.
In the second preferred embodiment of the flexible joint 186, the housings 250, 2S2 and teeth 260, 270 are constructed and arranged so that each of at least two loading housing teeth 260 make torque and rotation transmitting contact with a socket housing tooth 270 when torque is applied across the flexible joint 186.
This feature limits the twisting of the loading housing 250 relative to the socket housing 252 and thereby limits the lateral displacement o! the loading member 262 relative to the socket housing ZS0 dum to~ such twisting. Preferably, the loading and socket housings 250, 2Sa era constructed and arranged so that each of at least tvo loading housing teeth 260 makes torque and rotation transmitting contact vith a socket housing tooth 270 before the loading msabsr 262 makes torque transmitting contact with the socket housing 25=. This construction is preferably accomplished '~y designing and sizing the clearances, or spacing, between the contacting teeth 260, 270 and between the loading member and the socket housing bore 268 so that the teeth 260, 270 make sufficient contact to prevent further twisting of the loading housing 250 relative to the socket housing 252 before the loading member 262 makes torque transmitting contact with the socket housing.
Ths inventors have found that uncontrolled torque transmitting contact between the loading member 262 and the socket housing 252 results in failure of the loading member and also creates a net force which t$nds to undesirably straighten out the deflection 30 in the flexible joint 186. This problem and how it is solved by the flexible joint of the present invention may be batter understood by reviewing the shape of the teeth 260, 270 and the dynamics of the flexible joint 186 during the drilling o! a curved borehale.
Assuming there are two diametrically opposed loading housing teeth 260, that the loading housing 250 is on the uphole side of the def lection, that the def lection 30 is in a vertical plane, and that the loading housing teeth 260 are not coplanar with the deflection, as exemplified in Pig. 21, when the flexible joint 18b is deflected and comprsseively loaded with the weight-on-bit, at least one loading housing tooth 260 moves downwardly with respect to the plans of deflection 30 (which is the plane of the drawing sheet of Fig. 21, 3111, or 21H) into contact with the socket housing tooth 270 below it, as exemplified in Fig. 21A. Because of the downward angle of the loading housing teeth 260, the lower side of the cusp, or free end, of the downwardly rotating tooth 260 makes contact -~ 1-~v~~~, rith the socket houaing tooth 270 below it. In order for the intermeshed teeth 260, 270 to deflect or flex with respect to one another, there must be clearance or space around the internneshed teeth 260, 270. This clearance will normally be on the upper side (as shown in Fig. 21A) of the untorqued loading housing teeth 260 because of the downward force of the weight-on-bit which forces the loading housing teeth downwardly into contact with the socket housing~teeth 270 below the loading housing teeth 260. When the drill string is rotated and torque is applied across the flexible point 186, the loading housing L50 twists with respect to the socket housing 252 and the loading housing tooth 260 rotating downwardly (with respect to the plane of the deflection 30) is forced into contact with the socket housing tooth 270 below it, as exemplified in Fig. 21A. The loading housing 250 continues to twist with respect to the socket housing 252 until a second stabilizing contact capable of resisting further twisting is made.
I! there is insufficient clearance around the loading member 262, the loading member 262 will twist into torque transmitting contact with the socket housing 252. Preferably, there is sufficient clearance around the loading member 262 that the loading housing 250 continues to twist relative to the socket housing 252 until the upper side (as shoWtf in Fig. 21B) of the upwardly rotating loading housing tooth Z60 (which is on the diametrically opposite side of the loading housing from the downwardly rotating loading housing tooth 260) twists into contact with the socket housing tooth 270 above it and thereby makes a second stabilizing contact before the -~2-t.~ ~ n O .Je J 7.F ~
~oading member 262 makes torque transmitting contact with the socket housine~ 2s3.
Prelsrably, the at least two loading housing teeth 260 making torque and rotation transmitting contact with socket housing teeth 270 are looted at about diametrically opposed positions on the first end 254 of the loading housing 250. In the prototype flex joint 186, there are two loading housing teeth located at about diametrically opposite positions on the loading housing first end 254. By so plmcing the teeth 260, the forces created by the contacting teeth 260, 270 create a couple having a moment which is as nearly coaxial as possible with the axes 259, 269 of the flexible joint 186 and which therefore does not act to straighten out the dallection 30 crested by the flexible joint 186.
Further, referring to the example of Fig. 22, in the second prstsrrsd embodiment of the flexible joint 186, the socket housing 25Z includes a thrust bearing surface 274 disposed in the bore 268 of the socket housing 252 and the loading member 262 includes a thrust loading surtac. 276 for contacting the thrust bearing surface 274 and transferring thrust between the loading housing 250 and the socket housing 2~Z, as is necessary to transfer the weight-on~bit lros; tQm drill:string 24 to the curve drilling assembly 20.
In the second prsl~rt~d embodiment of the flexible joint 186, the.
thrust loading surtaco Z76 and the thrust bearing surlaca 274 are constructed and arranged so that the thrust loading surface 2~s, when contacting the thrust bearing surface 274, is pivotable about a pivotal center 278 which is about coplanar, or radially coincident (with respect to the longitudinal axes of the housings 250, 252j , with the torque transmitting contact between the loading housing teeth 260 and the socket housing teeth 270. This cop~lanarity or radial coincidence of the pivotal center 278 of the loading member 262 and the torque transmitting contact between the teeth 260, 270 is provided so that, if the loading member 262 makes torque transmitting contact with the socket housing 252 such contact~will be about radially coincident with the teeth 260, 270 making contact, and the moment of the resulting force couple will be directed about parallel to the axes 259, 269 0! the housings 250, 252. Directing the moment parallel to the axes 259, 269 of the housings 250, 252 reduces components of the moment which would straighten out the desired curve-creating deflection 30 in the flexible joint 186.
Another advantage of having the pivotal center 278 as nearly coplanar or radially coincident with the torque transmitting contact o! the teeth 260, 270 as possible, is that such a structural configuration reduces the clearance between the loading member 262 and socket housing 252 needed to prevent torque transmitting contact by the loading member 262. Referring to the example o! Pigs. 21 and 22, the magnitude o! deflection 30 is determined by the distance or angle the loading member 262 pivots with respect.to the socket housing 252 about pivotal center 2~8.
The farther the pivotal center 278 is from being radially coincident with the contact between the teeth 260, 270, the farther the loading housing teeth 26o deflect with respect to the socket ~~~g.~'~' 1 :. t J
'sousing teeth 270 as tho loading member 262 pivots a given distance about the pivotah center 278. The farther the loading housing teeth 260 must deflect with respect to the socket housing teeth 270, the greater the clearance or space between the intermeshed teeth 260, 270 must be to allow the teeth to deflect with respect to one another, particularly when the teeth are not in the plane of the deflection, as best exemplified in Figs. 21, 21A, and 218. The mots space or clsaranco there is between the teeth 260, 270, the greater the distance the upwardly rotating loading housing tooth 260 must twist to make contact with the socket housing tooth 270 above it (as best assn in Fig. 2iB) when the downwardly rotating loading housing tooth 260 is in contact with the socket housing tooth 2?0 below it (best seen in Fig. 21A). The greater the distance the upwardly rotating loading housing tooth 260 must twist, the more the loading member 262 must twist and the greater the clearance between the loading member 262 and socket housing 252 must bs to prevent torque transmitting contact by the loading member 26Z.
Ths preferred loading member 262, socket housing 252, and teeth 260, Z90 are constructed and arranged so that the thrust loading suslacs Z76 engages the thrust bearing surface 274 before the tsetb ZsO, Z70 ~raks thrust bearing contact when the flexible joint 186 ii subjsCtld to thrust, or compressive, forces, such as the weight-on-Dit exerted during drilling. As with the first embodiment o! the flexible joint 186, this arrangement is provided so that the flexible joint is flexible under thrust and compressive _~g_ ~ oadings. The inventors have found that it the teeth 260, 270 make thrust transmitting contact, such contact will tend to straighten out the desired bend or deflection 30, particularly if the thrust transmitting contact of the teeth 260, 270 is on the inside radius of the deflection 30.
The socket housing 252 further includes a thrust bushing 282 for transferring thrust between the loading member 262 and the socket housing 252. Ths thrust bushing includes a first end 284, a second end 286, and a bore 288 passing through the first and second ends 284, 286. Preferably, the first and 284 of the thrust bushing 282 includes the thrust bearing surface 274 for contacting the thrust loading surface 276 of tha loading member 262 and transferring thrust between the loading member 262 and the thrust bushing 283. The thrust bushing 282 is movably disposed in the socket housing bore 268 in such a manner that the thrust bearing surface 274 is lree to moos laterally in the bore 268 with the thrust loading surtace 276 and loading member 262. This lateral movement of the tlerust bearing surface 2?4 may be provided by designing and sizing the thrust bushing 282 to slide laterally in the bore 268 or to tilt in the bore 268. The lateral mobility of the thrust bearing surface 274 allows the thrust bushing 282 to transfer thrust to the socket housing 252 without transferring torque Pros the loading member 262 and without restricting the ability o! the loading member 262 to twist and/or move laterally with respect to the socket housing 252 as th. loading housing 250 so moves.

~~~~~~~;
The loading member 262 should be able to move laterally a sufficient distance that at least two loading housing teeth 260 (preferably two diametrically opposed loading housing teeth 260) can make contact with socket housing teeth 270. If the thrust bushing 282 does not move laterally with the loading member 262, it cars restrict the lateral motion of the loading member 262 due to twisting of the loading housing 250 relative to the socket housing 252 and. may prevent contact by at least two loading housing teeth 260. If at least two loading housing teeth do not make torque transmitting contact, the torque transmitted across the flexible joint 186 may be transmitted by one loading housing tooth 260 and the loading member 262 rather than by two loading housing teeth 260. The lateral movement of the thrust bushing 282 with the loading member 262 tacilitates movement of a second loading housing tooth 260 into contact with a second socket housing tooth 270.
The preferred socket housing 252 further includes a compression bearing 292 for transferring thrust between the thrust bushing 282 and the socket housing 252. The compression bearing 292 includes a compression bearing surface 294 disposed in the bore 268 0! the socket housing 252 between the thrust bushing second end 286 and the socJcet housing 252 with the compression bearing surface 294 adjacent the thrust bushing second end 286. The thrust bushing second end 286 and the compression bearing surface 294 are constructed and arranged so that the thrust bushing second end 2as slidably engages the compression bearing surlace 294 in order to enhance the ability o! the thrust bushing 282 and thrust bearing _77_ ~~~ t ~', e~
~~~.c~'~:
~~rtace 274 to move laterally with the loading member thrust loading surtacg.276.
Tha coapression bearing surface 294 may be formed in the second end 266 of the socket housing 252. In the preferred embodiment, referring to the example of Fig. 22, the compression bearing 292 is independent of the socket housing 252 and is placed in the bore 268 of the socket housing 252 between the thrust bushing 282 and the socket housing second end 266. The preferred compression bearing has a first end 296, a second end 298, and a bore 304. The compression bearing surface 294 is formed in the first end 296 of the compression bearing 29a. The compression bearing surface 294 and thrust bushing second end 286 may be planar so that the thrust bushing 282 simply slides on the compression bearing 292. Preferably, as exemplified in Fig. 22, the compression bearing surface 294 and thrust bushing second end 286 are mating convex and concave surfaces so that the thrust bushing 282 will tilt with respect to the longitudinal axis 269 of the socket housing Z5Z as the thrust bushing.second end 286 slides on the compression bearing surface 294. In the prototype flexible joint 186, the compression bearing surface 294 is concave in shape and the thsust bushi~fg second end 286 is convex in shape although either surlaco 186, Z91 say be convex with the other being concave .
As exeaplitied in Pig. 22, as is the thrust bushing 282, the compression bearing 29~ may be free to move laterally or radially with respect to the socket housing 252 and may also be tree to move axially in the socket housing 252 between the first and second ends _~8_ ~ ~ ~3 ~. ~ '~
264, 266 of the socket housing 252.
In the second preferred embodiment of the flexible joint 1~6, the loading member 262 further includes a tension loading shoulder 302 extending laterally outwardly from the loading member 262. The so<;ket housing 252 includes a tension bearing shoulder 304 extending laterally inwardly in the bore 268 of the socket housing 252 for capturing the tension loading shoulder 302 and for contacting the tension loading shoulder and transferring tension between the loading housing 250 and the socket housing 252. The tension loading shoulder 302 and the tension bearing shoulder 304 are constructed and arranged so that each of at least two loading housing teeth 260 makes torque and rotation transmitting contact with a socket housing tooth 270 when torqua is applied across the flexible joint 186 before the loading member 262 makes torque transmitting contact with the socket housing 252. The shoulders 302, 304 should be designed and constructed so that they do not restrict the ability of the loading housing 250 to twist relative to the socket housing 252. This construction may be accomplished by providing sufficient axial and lateral clearance around the loading member 262 and shoulders 302, 304 in the socket housing 252 that the loading member 26Z and tension loading shoulder 302 will not make torque transmitting contact with the socket housing 252 or tension bearing shoulder 304 before torque transmitting contact is made by at least two loading housing teeth 260 and socket housing teeth 270.
In order to provide the approximate coplanarity, or radial a '~~t~3~~ ~.~~~>
,oincidencs, between the pivotal center 278 of the loading member 262 and the torque transmitting contact of the teeth 260, 270, it is preferred that the tension bearing shoulder 304 be formed an the inside surface of the socket housing teeth 270. Consequently, the socket housing teeth 270 may be subjected to large tensile loadings, as is the tension bearing shoulder 304, when the curve drilling assembly 20 is lowered into or lifted out of a borehole 26. Tha preferred socket housing teeth 270, tension loading shoulder 302, and tension bearing shoulder 304 are constructed and arranged to maximize their tensile strength and to prevent splaying of the socket housing teeth 270 under tensile loading as much as possible. This construction may be accomplished by making the circumferential dimension of the socket housing teeth 270 on the socket housing 25~ as large as is possible (while still providing sufficient circumlerentisl dimension for the loading housing teeth 260 that the loading housing teeth 260 have adequate torsional strength and wear characteristics) and by shaping the tension loading shoulder 30Z and tension bearing shoulder 304 to reduce splaying of the socket housing teeth 270 as much as possible, as would be knowrf to one skilled in the art in view of the disclosure contained herein.
preferably, as exemplified in Fig. 22, the thrust loading surface Z76 and thrust bearing surface 274 are mating convex and concave surfaces in order to facilitate pivotal motion of the loading member 26a relative to the thrust bushing 282 when thrust is being transferred between the loading houaing 250 and socket _g0_ ~~u~.~i~ta~.a housing 252. As exemplified in Fig. 22, the preferred thrust loading surface 276 is convex in shape and the thrust bearing surface 274 is concave in shape, although either surface 274, 276 may be convex with the other being concave. In the prototype flexible joint 186, the convex shape of the thrust loading surface 276 and the tension loading shoulder 302 give the loading member 262 a generally spherical or ball shape.
In the preferred embodiment, in order to allow assembly and disassembly of the flexible joint 186, the socket housing first end 264 threadably engages the ~ockat housing second end 266.
Preferably, the socket housing first end 264 includes male threading which engages female threading in the bore of the socket housing second end 266. Ths socket housing second end 266 includes a seating surface 306, or a shoulder, in the socket housing bore 268 against which the compression bearing second end 298 seats in order to transfer thrust between the compression bearing 292 and the socket housing second end 266. The compression bearing second end 298 may include a flange for retaining the compression bearing 292 between the seating surface 306 and the socket housing first end 264, as axemplitied in Fig. 22. Tha compression bearing 292 and thrust bushing Z8Z may be placed in the bore 268 0! the socket housing second end Z66 and the socket housing first and 264 may then be threadingly engaged with the socket housing second end 266 to retain the thrust bushing 282 and compression bearing 292 in the socket housing bore 268. Also, the socket housing second end 266 may be disassembled from the socket housing first end 264 to allow -al-a~"~~L
access to and removal and installation of the loading member 262 in the loading housing 250. The socket housing second end 266 may be formed in the drill pipe, drill collar, mandrel, or the like to which the socket housing 252 is to be connected.
In the preferred embodiment, the loading member 262 is formed on a shaft 31A and the shaft 310 serves to connect the loading member 262 within the loading housing 250 in such a manner that the loading. member 262 may bs removed and replaced, as may be the thrust bushing 282 and compression bearing 292 and the socket housing 252. The preferred shaft 310 includes male threading for engaging female threading inside the bore 258 of the loading housing 250. The loading member 262, loading housing 250, socket housing 252, thrust bushing 282, compression bearing 292, and other components of the flexible joint 186 should be made of material suitable for the compressive, tensile, torsional, and other forces expected to be exerted by the drill string 24 on the curve drilling assembly 20 and drill bit 22 during drilling operations, as would be known to one skilled in the art in view of the disclosure contained herein.
The preferred flexible joint 186 is constructed and arranged so that the thrust loading surface 276 and thrust bearing surface 274 are in contact and the loading housing bore 258, loading member bore 253, socket housing bore 268, thrust bushing hors 288, and compression bearing bore 300 define a fluid passageway through the flexible joint 186 in all drilling positions of the flexible joint 186. Similarly to the first embodiment of the flexible joint 186, _82_ ~~~ ~.~r~.~~
'.he bore in the one of the loading member 262 and thrust bushing 282 to be placed uphole of the other may include a nozzle 312 for ace:elerating drilling fluid passing through the nozzle 312. The bore in the one of the loading member 262 and thrust bushing 282 to be placed on the downhole side of the flexible joint 186 may ine:luds a diffuser 314 for recovering fluid pressure dropped in the nozzle 312. As discussed with the first embodiment of the flexible joint 186, the nozzle 312 and diffuser 314 are provided to reduce leakage from inside the flexible joint 186 to the outside. The appropriate nozzle 312 or diffuser 314 may also extend into the compression bearing bore 300. The shaping and positioning of the nozzle 312 and diffuser 314, as well as their materials of construction, will be known to one skilled in the art in view of the disclosure contained herein.
The second preferred embodiment of the flexible joint 186 may be located at either of the uphole and downhole ends of the curve guide means 34, and is preferably placed at the same end of the curve guide means 34 as is the contact means 50. Referring to the example o! Fig. 16, the contact means 50 is preferably located at the uphole end 88 0! the mandrel 86 and the flexible joint 186 is connected between the drill string 24 and the uphole end 88 of the mandrel 8s..~ preferably, the socket housing second end 266 is formed by tbo upholei end 88 of the mandrel 86 and the socket housing first end 264 also forms and serves as the uphole retaining ring 140. The contact means 50 is preferably located on the outside surface of the socket housing first and 264.
_83_ .s~.i$r~'t~
Fig. 20 illustrates an embodiment in which the contact means 50 and flexible joint 186 are located at the downhole end 90 of the mandrel 86. In the example of Fig. 20, the socket housing second end 266 is formed by the downhole end 90 of the mandrel 86. Ths socket housing first end 264 is used to create the downhole retaining ring 142. Further, in the example a! Fig. 20, the contact means 50 is formed on the outside surface of the combination downhole retaining ring 142 and socket housing first end 264. Either of the loading housing 250 and socket housing 252 may be used to connect the flexible joint 186 to the mandrel 85.
In the embodiment of Fig. 20, the spacing member 178 is connected between the drill bit 22 and the flexible joint 186 in order to allow use of the flexible joint in uniform sizes and to thereby avoid expensive and time consuming custom manufacturing necessary to vary the distance L by varying the length of the flexible joint.
The outside surface 318 of the loading housing lirst end 254 and the outside surface 320 of the socket housing first end 264 are preferably beveled or chamfered, as exemplified in Figs. 16, 20, and 22, so that the teeth 250, 270 do not protrude and dig.into the borehole wall 28 when the flexible joint 186 is deflected.
5.0 TEST DJ~TA
Figs. 23-27 present test data which may be used to compare the curve drilling assembly 20 of the present invention with prior curve drilling assemblies. For the tests, a drill.truck wss set up to drill into a limestone block. In each test an 18 inch deep ~~~C~~. ~
:s ~orehole was first drilled to act as a pilot hole for the assembly.
Tha curved section of the borehole was then drilled in 1-1/2 foot increments. After drilling each 1-1/2 foot increment, the drilling was stopped and the rotational orientation of the curve drilling aseismbly in the borehols was visually checked. In most cases the borahola engaging means was pulled to the top of the hole and rerun before drilling resumed. After each borehole was drilled, it was caliperad with a tool that was especially designed for the tests.
The inclination of the borehole was measured and the curvature was calculated in 1/2 foot segments of axial length.
Fig. 23 presents the test results of a prior curve drilling assembly which included a conventional 3-7/8 inch diameter PDC
drill bit connected to the downhola end of a mandrel. Ths uphole end of the mandrel was connected to a flexible joint 186 similar to the one exemplified in Fig. 22A. An eccentrically bored rotatable collar (curve guide) was placed on the drill string on the uphole side of the flexible joint to create the deflection and to maintain the azimuthal direction o! the deflection in the borehole. A 3-~/8 inch reamer was located immediately uphole from the base portion 36 of the drill bit Z~. The assembly was sized to drill a 25 foot radius of curvature using the formula Re = Lz/ (d~ - dz~
where:
L = the~distance between the lowermost cutting edge of the _ loworsost gauge cutter on the drill bit and the uphole end o! the flexible joint;
_85_ da = the outside diameter of the drill bit; and d2 = the outside diameter of the flexible joint.
Referring to Fig. 23, it can be seen that the diameter of the drill borehole was approximately 1/8 inch overgauged and that the radius of curvature unpredictably oscillated around 45 feet. The radius of curvature was at least 20 feet greater than predicted with the formula at all of the measured intervals except one.
The cur~ra drilling assembly tested for Fig. 24 utilized the same configuration and flexible joint 186 as the assembly tested for Fig. 23, but the reamer was eliminated for the test of Fig. 24.
The assembly was designed for drilling a 25 foot radius of curvature using the formula L~/ (d~ - di) where:
L ~ the distance between the lowermost cutting edge of the lowermost gauge cutter and the uphole and of the sliding surface o! the contact means on the flexible joint;
d, ~ the outside diameter of the drill bit; and d= = the outside diameter of the contact ring. ' Referring to the data plotted in Fig. 24, it is seen that the assembly drilled a borahole diameter that was approximately 1/4 inch overgaugad and the radius of curvature unpredictably oscillated around 75 feet. The radius of curvature was at least 35 feet greater than predicted with the formula at all of the measured intervals except ons.
Fig. 25 prssents test results obtained utilizing an embodiment ~3 .~ (.t i.~
~t the curve drilling assembly 20 of the present invention similar to the embodiments of Fig. 20, but using the flexible joint 186 of Fig. 22A. A 3-15/16 inch diameter drill bit 22 according to the present invention was used. The flexible joint 186 was located between the downhole and 90 of the mandrel 86 and the drill bit 22 with the contact means 50 on the downhole end 90 of the mandrel 86.
The assembly was designed to drill a 30 foot radius of curvature using the formula as described for the test of Fig. 24. No reamer was used. Reterring to the data plotted on Fig. 25, it is seen that the assembly drilled a borehole that was approximately 1/15 inch oversized and which had a substantially constant radius of curvature of 30 feet.
Fig. 26 presents teat results utilizing an embodiment of the curve drilling assembly 20 of the present invention similar to the embodiment of Figs. 16 and 21, but using the flexible joint 186 of Fig. 22A. A 4-3/4 inch diameter drill bit 22 according to the present invention was used. The flexible joint 186 waa located between the drill string 24 and the curve guide means 34 with the contact means 50 on the uphole end 88 of the mandrel 86. The assembly was dasignsd to drill a 30 foot radius of curvature using the formula as duaribad for the test of Fig. 24. No reamer was used. Ratars3ng to the data plotted in Fig. 26, it is seen that the assembly drilled a borahola having an about gaugo diameter and having a substantially constant radius of curvature of 30 feet.
Fig. 27 presents test results utilizing an embodiment of the curve drilling assembly 20 of the present invention similar to the ~~3~~~~
embodiment of Fig. 20 and using the flexible joint 186 of Fig. 22.
A 3-15/ls inGt~- diameter drill bit 22 according to the present invention was used. Ths flexible joint 18s was located between the downhols end 90 of the mandrel 86 and the drill bit 22 with the contact means 50 on the downhole end 90 of the mandrel 86. The assembly was designed to drill a 30 foot radius of curvature using the formula as described for the test of Fig. 24. No reamer was used. Referring to the data plotted in Fig. 27, it is seen that the assembly drilled a borehole having an about gauge diameter and having a substantially constant radius of curvature of 30 feet.
Because of the limited vertical depth of some subterranean formations, in order to drill laterally into the formation with a curve drilling assembly, it is important that the curve drilling assembly be able to drill a curved borehols having a reliably predictable radius of curvature. By "reliably predictable" is meant a radius of curvature that is sufficiently constant and repeatable that the trajectory o! the curved borehole can be accurately predicted. I! the radius of curvature unpredictably varies (as in Figs. 23 and 24) the trajectory of the curved borehole will also unpredictably vary and the desired ability to predictably drill laterally i~nnta a selected formation will be diminished. As Figs.
25-27 illustsate,. the curve drilling assembly 20 of the present invention dsills a curved borehols having a radius of curvature which is reliably predictable with the given formula and which is substantially constant.
While presently preferred embodiments of the invention hbve _88-been described herein for the purpose of disclosure ~~~~
changes in the construction and arrangement oP parts and the performance of steps will suggest themselves to those skilled in then art, which changes are encompassed within the spirit of this in~rention, as defined by the following claims.

Claims

1. ~Curve drilling assembly connectable to a rotary drill string for drilling a curved subterranean borehole having an inside radius and an outside radius, the assembly comprising:
curve guide means connectable with the drill string for deflecting the drill string toward the outside radius of a curved borehole;
a rotary drill bit having a base portion disposed about a longitudinal bit axis for connection through the curve guide means with the drill string, a gauge portion disposed about the longitudinal bit axis and extending from the base portion, a face portion disposed about the longitudinal bit axis and extending from the gauge portion, and a plurality of cutting elements disposed on the face portion;
imbalance force means, rotatable with the drill string, for creating a net imbalance force along a net imbalance force vector substantially perpendicular to the longitudinal bit axis during drilling; and bearing means, rotatable with the drill string and looted in the curve drilling assembly near the cutting elements, for intersecting a force plane formed by the longitudinal bit axis and the net imbalance force vector and for substantially continuously contacting the borehole wall during drilling.

2. ~Curve drilling assembly of claim 1, in which the curve guide means comprises a mandrel rotatably disposed within a housing.

3. ~Curved drilling assembly of claim 2, wherein the rotational axis of the mandrel is skewed with respell to the longitudinal axis of the housing.

4. ~Curve drilling assembly of claim 2, wherein the drill string exerts an axial force on the curve drilling assembly; and wherein the deflection of the drill string creates a radial force component of the axial force component, the radial force component being directed toward the outside radius of the curved borehole; and further including: contact means for contacting the borehole wall and supporting the radial force component at one end of the mandrel on the borehole wall.

5. Curve drilling assembly of claim 2, further including a flexible joint, connectable between the drill bit and said one end of the mandrel, for flexibly connecting the curve drilling assembly to the drill bit.

6. Curve drilling assembly of claim 5, further including: a spacing member, detachably connectable between the drill bit and the flexible joint for varying the distance between the drill bit and the flexible joint.

7. Curve drilling assembly of claim 4, wherein the contact means comprises a contact ring disposed on and circumscribing the outside surface of the uphole end of the mandrel, the contact ring having a substantially smooth wear-resistant sliding surface for slidably contacting the borehole wall during drilling.

8. Curve drilling assembly of claim 4, wherein the contact ring extends radially from the outside surface of the mandrel farther than does the outside surface of the housing adjacent the outside radius of the curved borehole so that the curve drilling assembly has load-bearing contact with the borehole wail at the drill bit and the contact ring.

9. Curve drilling assembly of claim 2, wherein the housing includes an uphole end, a downhole end, an outside surface extending between the uphole end and the downhole end and a deflector, extending radially from the outside surface near the one end of the housing, for deflectively contacting the borehole wall in order to create the deflection and to keep the magnitude of the deflection between predetermined limits.

10. Curve drilling assembly of claim 2, further including a spacing member detachably connectable between the drill bit and the mandrel for varying the length of the assembly without modifying the mandrel or modifying the drill bit.

11. Curve drilling assembly connectable between a rotary drill string and drill bit for drilling a curved subterranean borehole having an inside radius and an outside radius, the assembly comprising:
curve guide means for deflecting the drill string toward the outside radius of a curved borehole when an axial force is exerted on the assembly through the drill string, and for creating a radial force directed towards the outside radius of the curved borehole, the curve guide means comprising a mandrel rotatably disposed within a housing and having an uphole end and a downhole end; and contact means for contacting the borehole wail and supporting the radial force component at one of the uphole end and the downhole end of the mandrel on the borehole wall during drilling.

12. Curve drilling assembly of claim 11, wherein the contact means is located at one end of the mandrel; and further including a flexible joint, connectable between said one end of the mandrel and the drill string, for flexibly connecting the assembly to the drill string.

13. Curve drilling assembly of claim 12, wherein the flexible joint is adopted to transmit rotation, torque, thrust and tension across a deflect drill string; wherein the flexible joint comprises:
a loading housing having a first end, a second end for connecting the loading housing to one of the mandrel and the drill string, a bore extending through the first and second ends, at least two loading housing teeth extending from the first end, and a loading member disposed in the bore and extending from the first end of the loading housing; and a socket housing for receiving the loading member, the socket housing having a first end, a second end for connecting the socket housing to one of the mandrel and the drill string, a bore extending through the first and second ends, and at least two socket housing teeth extending from the first end of the socket housing for intermeshing with the loading housing teeth in order to form a flexible connection between the loading and socket housings and to transmit rotation and torque between the loading housing and the socket housing, wherein the loading housing teeth and the socket housing teeth are constructed and arranged so that each of at least two loading housing teeth makes torque and rotation transmitting contact with a socket housing tooth when torque is applied across the flexible joint.

14. Curve drilling assembly of claim 13, wherein the socket housing comprises a thrust bearing surface disposed in the bore of the socket housing; wherein the loading member comprises a thrust loading surface for contacting the thrust bearing surface and transferring thrust between the loading housing and the socket housing; and wherein the thrust loading surface and the thrust bearing surface are constructed and arranged so that the thrust loading surface, when contacting the thrust bearing surface, is pivotable about a pivotal center which is about coplanar with the torque transmitting contact between the teeth.

15. Curve drilling assembly of claim 11, in which the housing comprises: borehole engaging means for preventing rotation of the housing with the mandrel during drilling; and mandrel engaging means for rotating the housing with the mandrel when the mandrel is rotated in an opposite direction to the drilling direction.

16. Curve drilling assembly of claim 11, in which the contact means comprises: a contact ring disposed on and circumscribing the outside surface of the one end of the mandrel, said contact ring extending radially from the outside surface of the mandrel farther than does the outside surface of the housing adjacent the outside radius of the curved borehole so that the curve drilling assembly has load-bearing contact with the borehole wall at the drill bit and the contact ring.

17. Curve drilling assembly of claim 11, further including signaling means for generating a signal when the housing is in a preselected rotational orientation with respect to the mandrel in order to monitor the rotational orientation of the housing from the surface of the earth, the signalling means comprising a signal ring detachably connectable to the housing and comprising a signal ring bushing, located between the signal ring and the mandrel, for facilitating rotation of the mandrel relative to the signal ring.

18. Curve drilling assembly of claim 11, wherein the housing includes an uphole end, a downhole end, and an outside surface extending between the uphole and downhole ends; and, in order to restrict lateral motion of the housing and mandrel and drill bit in the borehole and to keep the rotational axes of the housing and mandrel and drill bit coplanar with the plane of curvature of the curved borehole:
the outside surface at the downhole end of the housing has a downhole transverse dimension about equal to the outside diameter of the drill bit, the downhole transverse dimension extending in a plane about transverse to a plane of curvature of the curved borehole; and the outside surface at the uphole end of the housing has an uphole transverse dimension about equal to the outside diameter of the drill bit, the uphole transverse dimension extending in a plane about transverse to a plane of curvature of the curved borehole.