Medium curvature directional drilling method

Medium curvature deviated wellbores having a radius of curvature in the range of 200 feet to 400 feet are drilled with downhole drilling assemblies for drilling the curved wellbore portion and for correcting or holding the horizontal wellbore portion and which are connected to the end of a drillstem made up of elongated elastically bendable drillstem members which may be cyclically compressively stressed during rotation of the drillstem. The elastically bendable drillstem members are characterized by joint forming portions at opposite ends of an elongated tubular body and which are of a diameter which minimizes the tendency for the drillstem to buckle during drilling. Spaced apart stress bearing sleeves are attached to or integrally formed with the tubular body and are of a diameter greater than the body and preferably equal to the diameter of the tool joint portions. The drillstem is made up of the elastically bendable compressive service drillstem members extending through the curved and horizontal portions of the wellbore and heavy walled drill pipe or drill collars are provided in the drillstem in the vertical hole portion to impose compressive loads on the drillstem through the curved portion of the wellbore.

BACKGROUND OF THE INVENTION 
1. Field of the Invention 
The present invention pertains to a method and system for directional 
drilling of wellbores wherein the wellbore deviates from a substantially 
vertical portion of the wellbore to a substantially horizontal portion 
through a radius in the range of approximately 200 feet to 400 feet or a 
so-called build curvature of approximately 15.degree. to 25.degree. per 
100 feet of wellbore length. 
2. Background 
A large number of hydrocarbon containing earth formations exist in various 
parts of the world which have a vertical thickness of about 300 feet to 
400 feet or more. Many of these reservoirs are of a relatively low 
permeability type rock, such as limestone, and may have a substantial 
number of spaced apart natural vertical fractures. These types of 
formations or reservoirs are more likely to be economically produced if 
the wellbore is formed to extend generally horizontally through the 
formation to increase the amount of hole "depth" within the formation 
itself. Accordingly, forming such wellbores desirably involves drilling a 
vertical portion of the wellbore extending downward from the surface then 
curving the wellbore into a relatively highly deviated or near horizontal 
direction within and through the formation itself. It is also generally 
desirable that the radius of the deviated section of the wellbore which 
extends from the vertical to the horizontal portion be in the range of 
about 200 feet to 400 feet. In this way drilling may take place to 
identify the formation thickness, the wellbore may be plugged back to the 
top of the production zone or blocked by a whipstock of the like and then 
redrilled to form the transition portion from the vertical to the near 
horizontal. The curved and horizontally extending wellbore portions should 
be left in an open hole condition, if possible, to maximize wellbore 
length available for production of mineral values. 
Unfortunately, up to the time of the development of the present invention, 
known techniques for drilling highly deviated or generally horizontal 
wellbores fall into categories which are rather extreme with respect to 
the desired wellbore configurations for producing the types of formations 
mentioned. So called conventional deviated drilling techniques for 
transforming the wellbore from a vertical to generally horizontal 
direction use conventional rotary drilling equipment and methods wherein 
the radius of curvature of the drillstem generally cannot be reduced to 
less than about 1000 feet to 1200 feet and may range upward to a radius of 
3000 feet. Such drilling techniques may make it impossible to drill cost 
effective wells into productive zones having a thickness in the ranges 
abovementioned. 
The other technique used for drilling generally horizontal wellbores is 
sometimes referred to as drainhole drilling wherein deviation of the 
wellbore from the vertical to horizontal is through a rather small radius 
or high build curvature. High curvature drilling to provide drainholes and 
the like typically is carried out with a curvature radius of about 30 feet 
which produces a so-called wellbore angular build rate in the range of 
about 200.degree. per 100 foot of wellbore length. The total length of 
horizontal or deviated hole that may be produced by such a technique is 
typically in the range of about 100 feet to 500 feet. The drilling 
equipment is required to be very specialized and, accordingly, the cost 
per unit length of horizontal or deviated hole is relatively high. 
One rather important consideration in high curvature drilling techniques is 
the lack of control of the direction of the horizontal portion of the 
borehole. The high angular build rate is not conducive, with known 
equipment, to good directional control and the prospect of equipment 
failure makes this type of curved or deviated hole drilling relatively 
unattractive. 
Accordingly, considering the type and thickness of many known mineral value 
reservoirs which may be produced, there has been a continuing need to 
develop deviated or directional drilling methods which will provide the 
medium curvature geometry of the wellbore desired and which will overcome 
the disadvantages of conventional deviated hole drilling and so-called 
high curvature horizontal or drainhole type drilling techniques. It is to 
this end that the present invention has been developed with the discovery 
and development of a unique method and an improved drillstem system for 
drilling medium curvature wellbores with particular but not exclusive 
emphasis on wellbores drilled with curvatures in the range of 
approximately 15.degree. to 25.degree. per 100 feet of wellbore length or 
a wellbore radius of about 200 feet to 400 feet. 
SUMMARY OF THE INVENTION 
The present invention provides an improved method and system for drilling 
wellbores which have a curved portion with a radius of curvature which 
provides for extending the wellbore through pay zones having a total 
thickness in the range of about 200 feet to 400 feet. In accordance with 
an important aspect of the present invention, medium curvature wellbores 
may be drilled utilizing a unique arrangement of drillstem components and 
including an improved type of drillpipe extending through the curved 
portion of the wellbore. The drillstem is operated with compressive 
stresses exerted on the drillpipe and wherein the drillpipe may be rotated 
as needed in order to perform the drilling function in a desired 
direction. 
In accordance with another important aspect of the present invention, a 
method of drilling deviated or curved wellbores having a radius of 
curvature in the range of about 15.degree. to 25.degree. per 100 feet of 
wellbore length, but not specifically limited to this range, is provided 
wherein the drillstem is operated with downthrust exerted on the drillstem 
in such a way that the portion of the drillstem extending through the 
curved portion of the wellbore is biased toward the radially outermost 
wall of the wellbore and the drillstem is operated throughout 
substantially all of its length with compressive loading thereon. In this 
way, the tendency for forming an irregular wellbore cross-sectional 
configuration, known in the art as "keyseating", is minimized and chances 
of the drillstem becoming stuck in the wellbore are reduced. 
In accordance with yet another aspect of the present invention, a method 
and drillstem system for drilling medium curvature wellbores is provided 
wherein relatively heavy drillstem components are utilized to provide 
downthrust on the drillbit and outward bias on the curved portion of the 
drillstem. The so-called heavy drillstem components, sometimes known as 
thickwalled drillpipe and drill collars, are maintained in the 
substantially vertical portion of the wellbore to provide the downthrust 
on the bit without significantly increasing the drillstem rotary turning 
effort, since the heavier components do not forcibly engage the sidewall 
of the wellbore to increase drag on the drillstem. In particular, the 
improved drillstem system includes a compressive service drillpipe of a 
unique construction which is tolerant of large axial compressive stresses 
and relatively high curvature or bending to be imposed on the drillpipe 
while minimizing the amount of increased rotational effort required to be 
exerted on the drillstem and also alleviating the tendency for the 
drillpipe to buckle under compressive loads. 
The abovementioned features and advantages of the present invention, 
together with other superior aspects thereof will be further appreciated 
by those skilled in the art upon reading the detailed description which 
follows in conjunction with the drawing.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS 
In the description which follows, like parts are marked throughout the 
specification and drawing with the same reference numerals, respectively. 
The drawing figures are not necessarily to scale and certain features of 
the invention may be shown in somewhat schematic form in the interest of 
clarity and conciseness. 
Referring to FIG. 1, there is illustrated an improved medium curvature 
drilling system for drilling a curved wellbore into a subterranean 
formation generally designated by the numeral 10. The formation 10 
typically has a pay zone thickness in the range of about 400 feet and may 
lie several hundred or several thousand feet below the earth's surface 12. 
The drilling system of the present invention may utilize generally 
conventional surface equipment including a conventional rotary drilling 
rig 14 having a mast 16 and a conventional substructure 18 for supporting, 
for example, a rotary table 20. A conventional rotary drive member or 
kelly 22 extends through the rotary table 20 and is suspended from a 
traveling block 24 by a swivel 26. The swivel 26 may also be configured to 
have rotary drive means and be supported in such a way whereby the 
drillstem component 22 may be driven from its upper end rather than 
through the rotary table 20. 
In drilling a curved wellbore into the formation 10 a conventional, 
substantially vertical wellbore 30 may be first drilled through the 
formation 10 to determine its characteristics and overall thickness. When 
the upper boundary 11 of the formation 10 is located, the wellbore 30 may 
be cased with a casing string 32, if not previously required, and a cement 
plug 34 provided back to the boundary 11 so that the deviated or curved 
portion of the wellbore may be formed. 
In the view of FIG. 1, a curved wellbore has been formed which extends from 
a generally vertical wellbore portion 31 to a generally horizontally 
extending wellbore portion 33 through a curved portion 36. The curved 
portion 36 of the wellbore and the generally horizontally extending 
portion 33 are shown in an "open hole" condition which, typically, may be 
provided when drilling in relatively low permeability consolidated 
formations. One of the principal advantages of the method and system of 
this invention is the provision of extended wellbore length in an openhole 
condition thanks to the medium radius configuration. In accordance with 
the improved method and drilling system of the present invention, the 
radius R of the curved portion 36 of the wellbore may be predetermined to 
be in the range of approximately 200 feet to 400 feet so that the wellbore 
may extend through and remain within the formation region 10. The radius R 
does not have to be constant throughout the curved portion of the 
wellbore, that is, curvatures which are not true circular arcs may be 
provided as long as the change in direction of the wellbore accomplishes 
the objective of maintaining the wellbore in the desired zone. 
In the view of FIG. 1, the wellbore has been extended into the horizontal 
direction to form the horizontal portion 33 and a complete drillstem 
assembly utilized during this mode of drilling is illustrated in the 
drawing figure. While drilling the horizontal wellbore portion 33 to 
extend the length of wellbore in the formation region 10 continued 
extension of the horizontal portion of the wellbore may be carried out 
using one of several types of hole forming apparatus such as a so-called 
rotary "hold" tool comprising a conventional rotary bit 40 which is 
attached to a elongated generally conical stabilizer body 42 having a 
tapered outer wall surface which tapers axially from the end adjacent the 
bit 40 to the opposite end 43 wherein it is connected to a generally 
flexible section of drill pipe 44. The flexible pipe section 44 is 
connected to a portion of the drillstem made up of end to end connected 
sections of drillpipe 46 of a unique type to be described in further 
detail herein. The drillpipe sections 46 are disclosed and claimed in U.S. 
Pat. No. 4,674,580 issued June 23, 1987 to Frank J. Schuh and David D. 
Hearn and assigned to the assignee of the present invention. 
The drillpipe sections 46 make up a major portion of the drillstem assembly 
extending through the horizontal portion 33 of the wellbore and the curved 
portion 36. A directional survey unit 48 may be interposed in the 
drillstem to assist in determining the direction of extension of the 
wellbore portion 33. The directional survey unit 48 may be of a type 
commercially available from sources such as Gearhart Industries, Inc., 
Fort Worth, Texas, or Teleco Oil Field Services, Inc., of Lafayette, 
Louisiana. Accordingly, the drillstem system 39 illustrated, while forming 
the generally horizontal wellbore portion 33, is made up of a direction 
maintaining assembly such as the bit 40 and the stabilizer collar 42 and a 
plurality of end to end connected drillpipe sections 46 which extend 
through the horizontal wellbore portion 33 and the curved wellbore portion 
36. Alternatively, the direction maintaining or "hold" tool assembly can 
be replaced by a steerable downhole drill motor of a type available 
commercially from Norton Christiansen, Inc., Salt Lake City, Utah. 
The remainder of the drillstem system 39 in the vertical wellbore portion 
31 advantageously includes end to end connected relatively heavy drillstem 
sections 50, commonly known as drill collars. The drill collars 50 are 
relatively stiff and thick-walled drillstem sections which have a 
substantially greater weight per unit length than the drillpipe sections 
46. Preferably, the drill collars 50 include spiral grooves 51 formed on 
the outer surfaces thereof to minimize differential pressure effects due 
to the flow of drilling fluids within the annulus 53 formed between the 
drillstem and the wellbore wall surface. Near the upper end of the 
drillstem assembly or system 39 and below the uppermost drillstem member, 
such as the kelly 22, additional end to end connected drillstem sections 
52 are provided and which may comprise additional collars 50 or may 
comprise other so-called thickwalled drillpipe. The drillstem sections 52 
are those having a conventional elongated tubular stem portion and 
somewhat enlarged diameter end portions on which are formed external and 
internal threads, respectively, for coupling the drillstem sections in end 
to end relationship. The drillstem sections 52 may include a plurality of 
spaced apart collar portions 55 which add weight to the drillstem 
sections. Accordingly, the portion of the drillstem system 39 disposed in 
the generally vertical wellbore portion 31 is heavier per unit length than 
that portion formed by the drillstem sections 46. Even through the 
drillstem sections 50 and 52 are not necessarily of uniform density 
throughout their length, the overall average weight per unit length of the 
drillstem portion above the curved wellbore is greater than that which is 
in the curved and horizontal wellbore. U.S. Pat. No. 4,431,068 to T. B. 
Dellinger et al describes a drilling method wherein heavier drillstem 
sections are provided in the vertical wellbore portion of a deviated or 
curved wellbore. 
In accordance with a preferred method of drilling a medium curvature 
wellbore in accordance with the present invention, the relatively heavy 
portions of the drillstem system or assembly 39, including the drill 
collars 50 and the drillstem sections 52, are also interposed in the 
drillstem in such a way that they remain in the generally vertical portion 
of the wellbore 31. In this way, an improved method is provided wherein a 
downward or axial thrust force is exerted on the drillstem toward the bit 
40 which deflects the drillstem portion, generally designated by the 
numeral 54, in the curved wellbore portion 36 toward the radially 
outermost wall 37 of the wellbore portion 36 during drilling operations. 
By forcing the drillstem against the outer wall 37 of the wellbore portion 
36, the drillstem does not tend to cut into the inside portion of the 
wellbore wall to form a groove therein which can interfere with insertion 
and removal of the drillstem. This problem with prior art curved drilling 
practices is aggravated in relatively high curvature wellbores and wherein 
the drillstem is held in tension to control the weight on the drillbit. 
By maintaining the weight adding heavy or thick-walled drill pipe such as 
the drillstem sections 52 and the drill collars 50 in the vertical portion 
31 of the wellbore, as illustrated in FIG. 1, and by employing the unique 
drillstem portion made up of the drillpipe sections 46 in the curved and 
generally horizontal portion of the wellbore, the curved portion of the 
drillstem may be compressively stressed and the heavier drillstem 
components are not in engagement with the wall surfaces forming the 
horizontal or curved portions of the wellbore. Avoidance of this latter 
mentioned condition minimizes the drag on the drillstem created by heavy 
drillstem sections if they are located near the drillbit as in 
conventional drilling. The unique drillpipe sections 46 used in the 
drillstem system 39 between the vertical portion of the wellbore and the 
"bottom" of the wellbore are adapted to withstand cyclic bending stresses 
during rotation of the drillstem, prevent spiral or helical buckling due 
to the torque imposed on the drillstem during rotation thereof, and to 
withstand the compressive forces exerted on the drillstem by the weight of 
the portion of the drillstem extending through the vertical wellbore 
portion 31. 
It has been determined that a drillstem component such as one of the 
drillpipe sections 46 may be provided of reduced diameter through a major 
portion of its length and of reduced wall thickness to accommodate the 
bending stresses imposed thereon by providing each of the sections with a 
plurality of spaced apart sleeves, sometimes called "dummy tool joints". 
Referring now to FIG. 3, by way of example, there is illustrated one of 
the drillpipe sections 46 which is characterized by an elongated hollow 
tubular member 56 having integral or joined end portions 58 and 60 at 
opposite ends thereof and of a larger diameter than the member 56. The 
tool joint end portions 53 and 60 are respectively provided with internal 
threads 59 and external threads 61 forming so-called box and pin portions 
of the drillpipe section 46. A plurality of cylindrical collars or stress 
sleeves 62 are formed on the member 56 and are preferably spaced apart 
equally along the member between the tool joint portions 58 and 60. The 
sleeves 62 may be integrally formed with the member 56 or may be 
fabricated as split half-cylindrical sections which can be joined to the 
member or body 56 or can be slipped thereon before the joint portions 58 
and 60 are joined to the body 56. The number of sleeves 62 required to 
reduce the bending stresses to an acceptable level will vary depending on 
factors such as the diameter of the member or body 56, the maximum 
curvature to which the drillpipe sections 46 are exposed and the overall 
compressive or axial loading on the drillstem assembly. It is important 
that the outer diameter of the sleeves 62 be such in relation to the 
diameter of the wellbore as to minimize the chance of helical buckling of 
the drillpipe sections. 
The sleeves 62 act as supports for the drillpipe sections 46 when the 
drillstem is in engagement with the sidewalls of the wellbore, such as the 
wall 37 as illustrated in FIG. 1. A more detailed discussion of the 
so-called compressive service drillpipe sections 46 is provided in the 
aforementioned U.S. Pat. No. 4,674,580 to Frank J. Schuh and David D. 
Hearn. By way of example, drillpipe sections 46 designed for drilling a 
6.0 inch to 6.50 inch diameter wellbore may be of approximately 30 feet 
overall length and have a nominal weight per foot of length of 10.40 
pounds and 13.30 pounds, respectively. The lighter weight pipe described 
above has a nominal outside diameter of 2.88 inches for the member 56 and 
with an outside diameter of 5.0 inches for the tool joint sections 58 and 
60 and the sleeves 62. The spacing of the sleeves 62 may be at 7.5 foot 
intervals. A somewhat stiffer pipe having an outside diameter of 3.50 
inches for the member 56 also has tool joint sections 58 and 60 and 
sleeves 62 of 5.0 inches outside diameter with the spacing of the sleeves 
62 being at approximately 10.0 foot intervals. The sleeves 62 
advantageously provide for distribution of the bending loads on the 
drillstem sections 46 relatively evenly along the length thereof, prevent 
the body 56 from contacting the wellbore, and reduce the bending stress on 
the body 56. The total torque or turning effort to be exerted on the 
drillstem is also reduced due to reduced viscous effects and differential 
pressure effects acting on the drillstem. 
In a preferred method of forming a medium curvature wellbore such as the 
wellbore 31, 36, 33, illustrated in FIG. 1, if the formation region 10 
requires logging to determine its location and total depth, a generally 
vertical wellbore 30 is first drilled using conventional drilling 
techniques and equipment so that the upper and lower boundaries of the 
formation region of interest may be determined. Typically, the wellbore 30 
will be cased at least to the vicinity of the upper boundary 11 once it 
has been located. When the formation characteristics have been determined, 
the wellbore 30 may be plugged back with the cement plug 34 to the 
boundary 11 and the plug dressed off using a conventional rotary drilling 
bit such as the bit 40 at the end of a conventional drillstem. 
The curved portion 36 of the wellbore may be "kicked off" and formed using 
a drilling assembly of the type illustrated in FIG. 2. Referring to FIG. 
2, a rotary downhole drilling assembly or tool 70 is illustrated and 
includes a conventional rotary drillbit 72 similar to the bit 40 and a 
unique stabilizer tool or body 74. The stabilizer body 74 is directly 
connected to the bit 72 and comprises a tapered outer surface 76 having a 
somewhat convex curvature and tapering from the end 78 toward the end 80. 
The end 80 of the stabilizer body 74 is connected to a relatively flexible 
tubular section 82 having a box joint portion 84 whereby the tool 70 may 
be connected to one of the drillstem sections 46. The tool 70 is adapted 
to drill the curved wellbore section 36 through rotation of the drillstem 
system 39 until the wellbore reaches a generally horizontal direction 
whereby the tool 70 may be replaced with a tool comprising the bit 40 and 
stabilizer body 42. Circulation of drilling fluids may be carried out in a 
conventional manner through the drillstem system 39 to the bit 40 and 
upward through the wellbore annulus. 
Alternatively, certain types of downhole drill motors may be employed which 
do not require constant rotation of the drillstem, including types 
commercially available from Norton Christensen, Inc., of Salt Lake City, 
Utah. Still further, wellbore drilling assemblies such as of the type 
described in U.S. Pat. No. 4,523,652 to Frank J. Schuh and assigned to the 
assignee of the present invention may be employed to form the curved 
portion 36 of the wellbore. 
The drillstem assembly used for forming the curved portion 36 of the 
wellbore will comprise a sufficient number of drillpipe sections 46 to 
complete the curved portion and the desired horizontally extending portion 
33 while the weight adding drillstem sections 50 and 52 are used as 
required in the vertical portion 31 of the wellbore. The 
measurement-while-drilling unit 48 may be added to the drillstem system 39 
during formation of the curved portion 36 of the wellbore and used 
throughout the remainder of the drilling operation in order to determine 
when the wellbore has reached the horizontal direction and to provide for 
guidance of the horizontal extent of the wellbore. 
Once the wellbore has reached its maximum angular extent and it is decided 
to extend the wellbore horizontally, the drilling assembly 70 or a similar 
curved wellbore drilling motor is replaced with the drilling assembly 
comprising the bit 40 and the stabilizer 42 whereupon the continuing 
formation of the wellbore is carried out by rotation of the drillstem from 
the drilling rig 14. Alternatively, downhole rotary motors may be employed 
which provide for correcting and holding a direction of the horizontal 
wellbore portion. Such motors typically require limited rotation of the 
drillstem when holding a particular direction while maintaining the 
drillstem in a nonrotatable mode during correction of the direction of the 
wellbore or if a change in direction is desired. Thanks to the provision 
of the unique drillpipe sections 46, and the arrangement of the weight 
adding drill collars 50 and drillstem members 52 "uphole" or in the 
vertical portion of the wellbore, the drillstem is maintained biased 
against the radially outer most wall portion 37 of the curved portion 36 
of the wellbore to minimize the formation of an irregular cross-sectional 
shape of the wellbore and to minimize the chance of sticking the drillstem 
in the wellbore upon withdrawal therefrom. Certainly, the provision of the 
unique compressively stressed drillpipe sections 46 is important to the 
overall method and system of the present invention. 
Although preferred embodiments of the present invention have been described 
herein in detail, those skilled in the art will recognize that the 
improved method and system described herein may be subject to various 
modifications and substitutions without departing from the scope and 
spirit of the invention as recited in the appended claims.