Patent Publication Number: US-9410379-B2

Title: Downhole cutting tool

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims benefit of U.S. provisional patent application Ser. No. 61/580,443 filed Dec. 27, 2011, and entitled “Downhole Cutting Tool,” which is hereby incorporated herein by reference in its entirety. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     BACKGROUND 
     1. Field of the Invention 
     The present invention relates generally to downhole drilling operations. More particularly, the invention relates to tools for drilling boreholes. Still more particularly, the invention relates to reamer tools for enlarging boreholes during drilling operations. 
     2. Background of the Technology 
     An earth-boring drill bit is connected to the lower end of a drill string and is rotated by rotating the drill string from the surface, with a downhole motor, or by both. With weight-on-bit (WOB) applied, the rotating drill bit engages the formation and proceeds to form a borehole along a predetermined path toward a target zone. 
     In drilling operations, costs are generally proportional to the length of time it takes to drill the borehole to the desired depth and location. The time required to drill the well, in turn, is greatly affected by the number of times downhole tools must be changed or added to the drillstring in order to complete the borehole. This is the case because each time a tool is changed or added, the entire string of drill pipes, which may be miles long, must be retrieved from the borehole, section-by-section. Once the drill string has been retrieved and the tool changed or added, the drillstring must be constructed section-by-section and lowered back into the borehole. This process, known as a “trip” of the drill string, requires considerable time, effort and expense. Since drilling costs are typically on the order of thousands of dollars per hour, it is desirable to reduce the number of times the drillstring must be tripped to complete the borehole. 
     During oil and gas drilling operations, achieving good borehole quality is also desirable. However, achieving good borehole quality when drilling long horizontal boreholes can be particularly challenging. In particular, to keep the borehole path as close as possible to horizontal, the driller may have to periodically change the direction of the borehole path because gravity has a tendency to cause the drill bit drop slightly below horizontal. Consequently, the driller must make corrections to lift the drill bit back up to horizontal with a directional motor or rotary steerable assembly. Unfortunately, these repeated corrections can result in the formation of ledges and/or sharp corners in the borehole that interfere with the passage of subsequent tools therethrough. 
     A reamer can be used to remove ledges and sharp corners in the borehole. For a non-expanding reamer, the diameter of the reamer is limited by the diameter of the casing in the borehole that the drill bit and reamer must pass through. If a concentric non-expanding reamer having the same or smaller diameter than the drill bit is used with the drill bit, the reamer will generally follow the path of the drill bit and may not be effective in removing the ledges and/or sharp corners. An eccentric reamer reams the borehole to a diameter that is larger than the diameter of the drill bit and is typically effective in removing ledges and sharp corners. Most conventional eccentric reamers have a plurality of straight circumferentially-spaced blades lined with cutter elements designed to engage and shear the borehole sidewall. The blades are non-uniformly distributed about the tool, and thus, occupy less than the total circumference of the tool, thereby making the reamer eccentric. 
     Conventional practice is not to use an eccentric reamer with a drill bit when drilling a new section of the borehole for fear of causing damage to the casing and/or cutter elements on the reamer blades. Consequently, after drilling a new section of the borehole, the driller will make a dedicated trip out of the borehole to couple an eccentric reamer to the drill bit and then trip back into the borehole with the drill bit and reamer in order to ream the previously created section of borehole. Alternately, the driller may complete drilling of the new section with the drill bit alone, trip out of the borehole, and then return into the borehole with the eccentric reamer to ream the hole. However, in both cases, an additional trip of the drillstring is required to ream the borehole. 
     During drilling operations, the drill bit may be rotated from the surface (e.g., with a top drive or rotary table) and/or rotated with a downhole mud motor. In drilling operations where the drill bit is rotated solely with the downhole mud motor (i.e., when sliding), an eccentric reamer is typically not used behind the mud motor. In particular, when sliding, the eccentric reamer does not rotate, and thus, cannot open the hole. Further, since an eccentric reamer is typically used with a drill bit having a diameter smaller than the inner diameter of the casing string (to allow the reamer to pass therethrough), a non-rotating eccentric reamer cannot pass through a borehole formed by such a drill bit. 
     Accordingly, there remains a need in the art for improved eccentric reamers for smoothing the profile of a borehole during drilling operations by removing ledges and sharp corners along the borehole sidewall. Such improved eccentric reamers would be particularly well-received if they were suitable for use in connection with a drill bit drilling a new section of borehole, as well for use in connection with drill bits rotated solely with downhole motors. 
     BRIEF SUMMARY OF THE DISCLOSURE 
     These and other needs in the art are addressed in one embodiment by a tool for reaming a borehole. In an embodiment, the tool comprises a tubular body having a central axis, a first end, and a second end opposite the first end. In addition, the tool comprises an uphole reamer section mounted to the body and a downhole reamer section mounted to the body and axially positioned below the uphole reamer section. Each reamer section includes a first blade extending radially from the body. Each blade has an uphole end, a downhole end opposite the uphole end, a formation-facing surface extending from the uphole end to the downhole end, and a forward-facing surface extending radially from the body to the formation-facing surface. The formation facing surface of the first blade of the uphole reamer section is disposed at a radius R 1  measured perpendicularly from the central axis, wherein the radius R 1  increases moving from the uphole end to the downhole end of the first blade of the uphole reamer section. The formation facing surface of the first blade of the downhole reamer section is disposed at a radius R 1 ′ measured perpendicularly from the central axis, wherein the radius R 1 ′ decreases moving from the uphole end to the downhole end of the downhole reamer section. Further, the tool comprises a cutter element mounted to the formation facing surface of the first blade of each reamer section. The cutter element mounted to the first blade of the uphole reamer section extends to a radius relative to the central axis that is less than or equal to the radius R 1  at the downhole end of the first blade of the uphole reamer section, and the cutter element mounted to the first blade of the downhole reamer section extends to a radius relative to the central axis that is less than or equal to the radius R 1 ′ at the uphole end of the first blade of the downhole reamer section. 
     These and other needs in the art are addressed in another embodiment by a system for drilling a borehole in an earthen formation. In an embodiment, the system comprises a drillstring having a central axis, an uphole end, and a downhole end. In addition, the system comprises a drill bit disposed at the downhole end of the drillstring coaxially aligned with the drillstring. The drill bit is configured to rotate about the central axis in a cutting direction to drill the borehole to a diameter D 1 . Further, the system comprises a first reamer section mounted to the drillstring between the drill bit and the uphole end. The first reamer section is configured to rotate about the central axis in the cutting direction to ream the borehole to a diameter D 2  that is greater than diameter D 1 . The first reamer section includes a pair of first blades and a pair of second blades, wherein the blades of the first reamer section are uniformly circumferentially spaced with the first blades circumferentially adjacent each other and the second blades circumferentially adjacent each other. Each blade has an uphole end, a downhole end opposite the uphole end, and a formation-facing surface extending from the uphole end to the downhole end. The formation facing surface of each first blade is disposed at a radius R 1  relative to the central axis, wherein the radius R 1  of the formation facing surface of each first blade decreases moving from the uphole end to the downhole end. Each second blade extends radially to a maximum radius R 2  relative to a reamer axis that is parallel to and radially offset from the central axis, wherein the maximum radius R 2  that is less than the radius R 1  at the downhole end of each first blade. Still further, the system comprises a plurality of cutter elements mounted to the formation facing surface of each of the first blades, wherein each cutter element extends to a radius relative to the central axis that is less than or equal to the radius R 1  at the uphole end of each of the first blades of the first reamer section. Each cutter element has a forward-facing cutting face relative to the cutting direction. 
     These and other needs in the art are addressed in another embodiment by a method for drilling a borehole. In an embodiment, the method comprises coupling a drill bit to a lower end of a drillstring. In addition, the method comprises coupling a reaming tool to the drillstring between the drill bit and an uphole end of the drillstring, wherein the reaming tool includes a tubular body having a central axis and a downhole eccentric reamer section extending radially from the body; wherein the downhole eccentric reamer section has a pass through diameter D 1 ′. The downhole reamer section is configured to rotate about the central axis of the tubular body in a cutting direction to ream the borehole to a diameter D 2 . The downhole eccentric reamer section further comprises a cutting blade extending radially from the tubular body, the cutting blade having an uphole end, a downhole end, and a formation-facing surface disposed at a radius R 1  measured radially from the central axis, wherein the radius R 1  decreases moving from the uphole end to the downhole end. In addition, the downhole eccentric section comprises a plurality of cutter elements mounted to the formation facing surface of the cutting blade, wherein each cutter element extends to a radius relative to the central axis that is less than or equal to the radius R 1  of the formation facing surface at the uphole end of the cutting blade. Further, the method comprises lowering the downhole eccentric reamer section through a casing having a central axis and an inner diameter D i  that is greater than or equal to the pass through diameter D 1 ′. The inner diameter D i  is less than the diameter D 2 . Still further, the method comprises offsetting the central axis of the tubular body from the central axis of the casing while lowering the downhole eccentric reamer section through the casing. 
     Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which: 
         FIG. 1  is a schematic view of an embodiment of a drilling system in accordance with the principles described herein; 
         FIG. 2  is a front side view of the downhole cutting tool of  FIG. 1 ; 
         FIG. 3  is a back side view the downhole cutting tool of  FIG. 1 ; 
         FIG. 4  is a cross-sectional top view of the downhole cutting tool of  FIG. 2  taken along section IV-IV and illustrating the uphole reamer section; 
         FIG. 5  is a cross-sectional bottom view of the downhole cutting tool of  FIG. 2  taken along section V-V and illustrating the lower reamer section; 
         FIG. 6  is a bottom view of the drill bit and downhole cutting tool of  FIG. 1 ; 
         FIG. 7  is an enlarged partial view of the system of  FIG. 1  illustrating the drill bit and the cutting tool being lowered through the casing at the upper end of the borehole; and 
         FIG. 8  is a bottom view of the lower reamer section of  FIG. 7  in the casing. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment. 
     Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness. 
     In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . . ” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. Any reference to up or down in the description and the claims is made for purposes of clarity, with “up”, “upper”, “upwardly”, “uphole”, or “upstream” meaning toward the surface of the borehole and with “down”, “lower”, “downwardly”, “downhole”, or “downstream” meaning toward the terminal end of the borehole, regardless of the borehole orientation. 
     Referring now to  FIG. 1 , an embodiment of a drilling system  10  is schematically shown. In this embodiment, drilling system  10  includes a drilling rig  20  positioned over a borehole  11  penetrating a subsurface formation  12 , a casing  14  extending from the surface into the upper portion of borehole  11 , and a drillstring  30  suspended in borehole  11  from a derrick  21  of rig  20 . Casing  14  has a central or longitudinal axis  15  and an inner diameter D 14 . Drillstring  30  has a central or longitudinal axis  31 , a first or uphole end  30   a  coupled to derrick  21 , and a second or downhole end  30   b  opposite end  30   a . In addition, drillstring  30  includes a drill bit  40  at downhole end  30   b , a downhole cutting tool  100 , axially adjacent bit  40 , and a plurality of pipe joints  33  extending from cutting tool  100  to uphole end  30   a  . Pipe joints  33  are connected end-to-end, and tool  100  is connected end-to-end with the lowermost pipe joint  33  and bit  40 . A bottomhole assembly (BHA) can be disposed in drillstring  30  proximal the bit  40  (e.g., axially between bit  40  and tool  100 ). 
     In this embodiment, drill bit  40  is rotated by rotation of drillstring  30  from the surface. In particular, drillstring  30  is rotated by a rotary table  22  that engages a kelly  23  coupled to uphole end  30   a  of drillstring  30 . Kelly  23 , and hence drillstring  30 , is suspended from a hook  24  attached to a traveling block (not shown) with a rotary swivel  25  which permits rotation of drillstring  30  relative to derrick  21 . Although drill bit  40  is rotated from the surface with drillstring  30  in this embodiment, in general, the drill bit (e.g., drill bit  40 ) can be rotated with a rotary table or a top drive, rotated by a downhole mud motor disposed in the BHA, or combinations thereof (e.g., rotated by both rotary table via the drillstring and the mud motor, rotated by a top drive and the mud motor, etc.). For example, rotation via a downhole motor may be employed to supplement the rotational power of a rotary table  22 , if required, and/or to effect changes in the drilling process. Thus, it should be appreciated that the various aspects disclosed herein are adapted for employment in each of these drilling configurations and are not limited to conventional rotary drilling operations. 
     During drilling operations, a mud pump  26  at the surface pumps drilling fluid or mud down the interior of drillstring  30  via a port in swivel  25 . The drilling fluid exits drillstring  30  through ports or nozzles in the face of drill bit  40 , and then circulates back to the surface through the annulus  13  between drillstring  30  and the sidewall of borehole  11 . The drilling fluid functions to lubricate and cool drill bit  40 , and carry formation cuttings to the surface. 
     Referring now to  FIGS. 2 and 3 , downhole cutting tool  100  is shown. As will be described in more detail below, tool  100  functions to ream borehole  11  as drill bit  40  drills the borehole  11 . In this embodiment, downhole cutting tool  100  includes an elongate tubular body  101 , a first or uphole eccentric reamer section  110 , and a second or downhole eccentric reamer section  130  axially spaced below the uphole reamer section  110 . Tubular body  101  has a central or longitudinal axis  105  coincident with drillstring axis  31  (not shown in  FIGS. 2 and 3 ), a first or uphole end  101   a , a second or downhole end  101   b  opposite the uphole end  101   a , a generally cylindrical outer surface  102  extending axially between ends  101   a, b , and an inner through bore  103  extending axially between ends  101   a, b . Bore  103  allows for the passage of drilling fluid through tool  100  in route to bit  40  (not shown in  FIGS. 2 and 3 ). During drilling operations, tool  100  is rotated about axis  105  in a cutting direction  106 . 
     Outer surface  102  of body  101  includes an annular cylindrical recess  104  axially disposed between the ends  101   a, b . Thus, the diameter of outer surface  102  is reduced within recess  104 . In this embodiment, recess  104  is axially equidistant from each ends  101   a, b . In this embodiment, downhole end  101   b  comprises a male pin-end  108  that connects to a mating female box-end of drill bit  40 , and uphole end  101   a  comprises a female box-end  107  that connects to a mating male pin-end at the lower end of the lowermost pipe joint  33 . 
     Referring now to  FIGS. 2-5 , each reamer section  110 ,  130  includes a plurality of circumferentially-spaced helical blades  111 ,  112  and  131 ,  132 , respectively, extending radially outward from recess  104 . In this embodiment, blades  111 ,  112 ,  131 ,  132  are integrally formed as a part of tool body  101 . In other words, blades  111 ,  112 ,  131 ,  132  and body  101  are a unitary single-piece. As will be described in more detail below, blades  111 ,  131  are designed to cut and shear the sidewall of borehole  11 , while blades  112 ,  132  generally function as stabilizing bearing surfaces during rotation inside of the casing  14 . 
     As best shown in  FIGS. 4 and 5 , in this embodiment, uphole reamer section  110  includes four parallel blades—a pair of blades  111  and a pair of blades  112 ; and downhole reamer section  130  includes four parallel blades—a pair of blades  131  and a pair of blades  132 . In this embodiment, blades  111 ,  112  of uphole reamer section  110  are uniformly circumferentially-spaced about body  101 , and blades  131 ,  132  of downhole reamer section  130  are uniformly circumferentially-spaced about body  101 . Thus, the four total blades  111 ,  112  are angularly spaced 90° apart about axis  105 , and the four total blades  131 ,  132  are angularly spaced 90° apart about axis  105 . In addition, blades  111 ,  112  are arranged such that blades  111  are circumferentially adjacent each other and blades  112  are circumferentially adjacent each other. Thus, each blade  111  is angularly spaced 180° from one blade  112 . Likewise, blades  131 ,  132  are arranged such that blades  131  are circumferentially adjacent each other and blades  132  are circumferentially adjacent each other. Thus, each blade  131  is angularly spaced 180° from one blade  132 . 
     Referring again to  FIGS. 2 and 3 , each blade  111 ,  112 ,  131 ,  132  has a first or uphole end  140   a , a second or downhole end  140   b , a formation-facing surface  141 , a forward-facing or leading surface  142 , and a generally rear-facing or trailing surface  143 . Each surface  141 ,  142 ,  143  extends between ends  140   a, b  of the corresponding blade  111 ,  112 ,  131 ,  132 . Surfaces  141  are radially spaced from outer surface  102  and face the sidewall of borehole  11  during drilling operations, and surfaces  142 ,  143  extend radially from outer surface  102  to surface  141 . Surfaces  142  are termed “forward-facing” or “leading” as they lead the corresponding blade  111 ,  112 ,  131 ,  132  relative to the cutting direction of rotation  106 ; and surfaces  143  are termed “rear-facing” or “trailing” as they trail the corresponding blade  111 ,  112 ,  131 ,  132  relative to the cutting direction of rotation  106 . In addition, blades  111 ,  131  are generally circumferentially aligned and blades  112 ,  132  are generally circumferentially aligned. More specifically, downhole end  140   b  of each blade  111 ,  112  is circumferentially aligned with uphole end  140   a  of one blade  131 ,  132 , respectively, and uphole end  140   a  of each blade  111 ,  112  is circumferentially aligned with downhole end  140   b  of one blade  131 ,  132 , respectively. 
     Referring still to  FIGS. 2 and 3 , blades  111 ,  112 ,  131 ,  132  extend generally helically about tool body  101 , and as previously described, blades  111 ,  112  are parallel to each other and blades  131 ,  132  are parallel to each other. However, blades  111 ,  112  are not parallel to blades  131 ,  132 —blades  111 ,  112  and blades  131 ,  132  extend helically in opposite directions about tool body  101 . In particular, downhole end  140   b  of each blade  111 ,  112  of uphole reamer section  110  leads the blade  111 ,  112  relative to the cutting direction of rotation  106 , whereas uphole end  140   a  of each blade  131 ,  132  of downhole reamer section  130  leads the blade  131 ,  132  relative to the cutting direction of rotation  106 . 
     As best shown in  FIGS. 4 and 5 , formation facing surface  141  of each blade  111 ,  131 , is disposed at an outer radius R 111  and R 131 , respectively, measured radially from axis  105 , to the formation facing surface  141 . Further, the formation facing surface  141  of each blade  112 ,  132  is disposed at an outer radius R 112 , R 132 , respectively, measured radially from an axis  105 ′, which is parallel to and radially offset from the central axis  105  of tool  100 , to the formation facing surface  141 . In addition, blades  111 ,  112  of uphole reamer section  110  taper or incline radially inward moving from downhole end  140   b  to uphole end  140   a , and blades  131 ,  132  of downhole reamer section  130  taper or incline radially inward moving from uphole end  140   a  to downhole end  140   b . Thus, radius R 111 , R 112  of formation facing surface  141  of each blade  111 ,  112 , respectively, decreases moving from downhole end  140   b  to uphole end  140   a , and radius R 131 , R 132  of formation facing surface  141  of each blade  131 ,  132 , respectively, decreases moving from uphole end  140   a  to downhole end  140   b . Consequently, radius R 111 , R 112  of formation facing surface  141  of each blade  111 ,  112 , respectively, is at a maximum at downhole end  140   b  and at a minimum at uphole end  140   a , whereas radius R 131 , R 132  of formation facing surface  141  of each blade  131 ,  132 , respectively, is at a maximum at uphole end  140   a  and at a minimum at downhole end  140   b.    
     For purposes of clarity and further explanation, the maximum radius R 111 , R 112  of formation facing surface  141  of each blade  111 ,  112 , respectively, (i.e., the radius R 111 , R 112  at each downhole end  140   b ) is referred to as radius R 111max , R 112max , respectively; and the maximum radius R 131 , R 132  of formation facing surface  141  of each blade  131 ,  132 , respectively, (i.e., the radius R 131 , R 132  at each uphole end  140   a ) is referred to as radius R 131max , R 132max , respectively. In this embodiment, each radius R 111max  and each radius R 131max  is the same, and each radius R 112max  and each radius R l32max  is the same. Still further, each radius R 111max , R 131max  is greater than each radius R 112max , R 132max . Since each radius R 111max  is greater than each radius R 112max , and blades  111 ,  112  are arranged with blades  111  circumferentially adjacent and blades  112  circumferentially adjacent, uphole reamer section is eccentric relative to axis  105 ; and since each radius R 131max  is greater than each radius R 132max , and blades  131 ,  132  are arranged with blades  111  circumferentially adjacent and blades  112  circumferentially adjacent, downhole reamer section is also eccentric relative to axis  105 . 
     Referring again to  FIGS. 2-5 , each reamer section  110 ,  130  includes a plurality of cutter elements  150  mounted to the formation facing surface  141  of each blade  111 ,  131 . In particular, on each blade  111 ,  131 , cutter elements  150  are arranged adjacent one another in row along the leading edge of the blade  111 ,  131  (i.e., along the intersection of surfaces  141 ,  142 ). On blades  111  of uphole reamer section  110 , cutter elements  150  are positioned proximal uphole ends  140   a ; and on blades  131  of downhole reamer section  130 , cutter elements  150  are positioned proximal downhole ends  140   b . In particular, cutter elements  150  on blades  111  are axially positioned side-by-side along the upper half of each blade  111 , and cutter elements  150  on blades  131  are axially positioned side-by-side along the lower half of each blade  131 . 
     In general, each cutter element  150  can be any suitable type of cutter element known in the art. In this embodiment, each cutter element  150  comprises an elongate cylindrical tungsten carbide support member  151  and a hard polycrystalline diamond (PD) cutting layer  152  bonded to the end of the support member  151 . Support member  151  of each cutter element  150  is received and secured in a pocket formed in surface  141  of the corresponding blade  111 ,  131  with cutting layer  152  exposed on one end. Each cutting layer  152  has a generally forward-facing cutting face  153  relative to the cutting direction of rotation  106 . In this embodiment, cutting faces  153  are substantially planar, but may be convex or concave in other embodiments. 
     Each cutting face  153  extends to an extension height measured radially from the corresponding formation-facing surface  141  to the radially outermost tip of the cutting face  153 . In this embodiment, the extension height of each cutting face  153  is the same. However, since the radii R 111  of formation facing surfaces  141  of blades  111  decrease moving from downhole ends  140   b  to uphole ends  140   a , the radii to which cutting faces  153  mounted to blades  111  extend relative to axis  105 ′ progressively decrease moving toward uphole end  140   a . Likewise, since the radii R 131  of formation facing surfaces  141  of blades  131  decrease moving from uphole end  140   a  to downhole end  140   b , the radii to which cutting faces  153  mounted to blades  131  extend relative to axis  105 ′ progressively decrease moving toward downhole end  140   b . In this embodiment, the lowermost cutting face  153  mounted to each blade  111  extends to a radius equal to radius R 111max , with the remaining cutting faces  153  mounted to each blade  111  extending to radii that progressively decrease moving towards uphole end  140   a ; and the uppermost cutting face  153  mounted to each blade  131  extends to a radius equal to radius R 131max , with the remaining cutting faces  153  mounted to each blade  131  extending to radii that progressively decrease moving towards downhole end  140   b.    
     As previously described, radii R 111max , R 131max  of blades  111 ,  131 , respectively, are greater than radii R 112max , R 132max  of blades  112 ,  132 , respectively, and further, blades  111 ,  131  include cutter elements  150  mounted thereto for reaming the sidewall of borehole  11 . Thus, blades  111 ,  131  may also be referred to as “cutting” blades. Radii R 112max , R 132max  of blades  112 ,  132 , respectively, are less than radii R 111max , R 131max  of blades  111 ,  131 , respectively, blades  112 ,  132  do not include any cutter elements (e.g., cutter elements  150 ), and blades  112 ,  132  generally function as a stabilizing bearing surface during rotation inside of the casing. Thus, blades  112 ,  132  may also be referred to as “stabilizing” blades. 
     As best shown in  FIG. 4 , uphole reamer section  110  has a minimum pass through diameter D 110 , which represents the minimum diameter hole or bore through which uphole reamer section  110  can be tripped, and as best shown in  FIG. 5 , downhole reamer section  130  has a minimum pass through diameter D 130 , which represents the minimum diameter hole or bore through which downhole reamer section  130  can be tripped. Referring again to  FIGS. 2-5 , in this embodiment, due to the positioning, orientation, and configuration of blades  111 ,  112 ,  131 ,  132  (e.g., blades  111 ,  131  are circumferentially aligned; blades  112 ,  132  are circumferentially aligned; radii R 111max , R 131max  are the same and measured relative to the same axis  105 ; and radii R 112max , R 132max  are the same and measured relative to the same axis  105 ′) and associated cutter elements  150 , uphole reamer section  110  and downhole reamer section  130  are mirror images of each other across a reference plane  120  positioned midway between reamer sections  110 ,  130  and oriented perpendicular to axes  105 ,  105 ′. Consequently, pass through diameters D 110 , D 130  are the same and are concentrically aligned such that both reamer sections  110 ,  130  can simultaneously pass through casing  14  having inner diameter D 14  equal to or greater than pass through diameters D 110 , D 130 . In other words, if inner diameter D 14  of casing  14  is equal to or greater than pass through diameters D 110 , D 130 , then reamer sections  110 ,  130 , respectively, can pass therethrough. However, if inner diameter D 14  of casing is less than pass through diameters D 110 , D 130 , then reamer sections  110 ,  130 , respectively, cannot pass therethrough. 
     Referring again to  FIGS. 4 and 5 , when uphole reamer section  110  is rotated in cutting direction  106  about axis  105 , it cuts or reams a hole to a reaming diameter D 110′ , and when lower reamer section  130  is rotated in cutting direction  106  about axis  105 , it cuts or reams a hole to a reaming diameter D 130′ . Reaming diameter D 110′  is greater than pass through diameter D 110 , thereby enabling uphole reamer section  110  to ream borehole  11  to diameter D 110′  that is greater than the pass through diameter D 110 . Similarly, reaming diameter D 130′  is greater than pass through diameter D 130 , thereby enabling downhole reamer section  130  to ream borehole  11  to diameter D 130′  that is greater than pass through diameter D 130 . In embodiments described herein, each reaming diameter D 110′ , D 130′  is preferably greater than each pass through diameter D 110 , D 130 , respectively; more preferably each reaming diameter D 110′ , D 130′  greater than each pass through diameter D 110 , D 130 , respectively, and less than 112% of each pass through diameter D 110 , D 130 , respectively; and even more preferably each reaming diameter D 110′ , D 130′  is greater than each pass through diameter D 110 , D 130 , respectively, and less than 105% of each pass through diameter D 110 , D 130 , respectively. 
     Although stabilizing blades  112 ,  132  do not include any cutter elements  150  in this embodiment, in other embodiments, one or more cutter elements  150  can be mounted to formation facing surface  141  of one or more of the stabilizing blades  112  proximal uphole end  140   a , and one or more cutter elements  150  can be mounted to formation facing surface  141  of one or more of the stabilizing blades  132  proximal downhole end  140   b . However, such cutter elements  150  mounted to blades  112 ,  132  do not extend radially beyond radii R 112max , R 132max  of blades  112 ,  132 , respectively. 
     Although each reamer section  110 ,  130  has been shown and described as having four blades (i.e., uphole reamer section  110  includes two cutting blades  111  and two stabilizing blades  112 ; and downhole reamer section  130  includes two cutting blades  131  and two stabilizing blades  132 ), in general, the total number of blades (e.g., blades  111 ,  112 ,  131 ,  132 ) on each reamer section (e.g., reamer sections  110 ,  130 ) can be more or less than four. For example, in some embodiments, each reamer section includes five or six helical blades instead of four. However, regardless of the total number of blades on each reamer section, the blades on each reamer section are preferably uniformly circumferentially-spaced. In addition, in embodiments where there is an odd number of total blades on a reamer section, there is preferably at least one more cutting blade than stabilizing blade. 
     Referring now to  FIGS. 6 and 7 , drill bit  40  is connected to downhole end  101   b  of tool body  101  and has a central axis  45  coaxially aligned with axis  105 , a bit body  41 , and a shank  42 . During drilling operations, bit  40  is rotated about axis  45  in cutting direction  106  previously described. In this embodiment, bit  40  is a fixed cutter bit including a plurality of blades  43  extending along the outside of body  41 . A plurality of cutter elements  150  as previously described are disposed side-by-side along the leading edge of each blade  43  such that each cutting face  153  is generally forward-facing relative to the cutting direction of rotation  106 . Bit  40  has a maximum or full gage diameter D 40  defined by the radially outermost reaches of blades  43  and cutter elements  150 . In this embodiment, full gage diameter D 40  of bit  40  is greater than the pass through diameter D 110 , D 130  of each reamer section  110 ,  130 , respectively and less than the reaming diameter D 110′ , D 130′  of each reamer section  110 ,  130 , respectively. A plurality of ports or nozzles  44  are disposed in body  41  and are configured to allow the flow of drilling fluids (e.g., drilling mud) therethrough during drilling operations to lubricate and cool drill bit  40 , and to carry formation cuttings to the surface. 
     Referring now to  FIG. 7 , during drilling operations, tool  100  and drill bit  40  are rotated in cutting direction  106 . With WOB applied, bit  40  engages and cuts the formation. As chips of the formation are broken off and transported to the surface with drilling mud, bit  40  advances along a predetermined trajectory to lengthen borehole  11 . During the initial stages of drilling immediately below casing  14 , tool  100  is disposed within casing  14  and is rotated with string  30  to rotate bit  40 . With most conventional eccentric reamers, rotation of the reamer within casing (e.g., casing  14 ) is generally discouraged as the reamer may undesirably cut and damage the casing, potentially comprising the integrity of the well. In particular, most eccentric reamers are sized such that they can be advanced axially through the casing, and then ream the borehole to a diameter greater than the diameter of the casing. To maximize the diameter of the reamed borehole, conventional reamers are typically sized as large as possible while being able to be advanced through the casing. Consequently, when such an eccentric reamer is rotated within the casing, it may ream the inside of the casing to a diameter greater than the inner diameter of the casing itself, thereby potentially damaging the casing. However, in embodiments described herein, reamer sections  110 ,  130  are configured such that they can be rotated within casing  14  without posing a significant risk of damage to casing  14 . 
     As best shown in  FIG. 8 , reamer sections  110 ,  130  are sized as large as possible while still being able to pass through casing  14 —pass through diameters D 110 . D 130  are equal to or slightly less than the inner diameter D 14  of casing  14 . It should be appreciated that even though  FIG. 8  only shows the upper reamer section  110  within casing  14 , lower reamer section  130  functions in the same manner. Due to the eccentricity of reamer sections  110 ,  130 , when tool  100  is disposed in casing  14 , central axis  105  of tool  100  is radially offset from central axis  15  of casing  14  and axis  105 ′ is coaxially aligned with axis  15  of casing  14 . As previously described, if tool  100  is permitted to rotate in cutting direction  106  about tool axis  105 , reamer sections  110 ,  130  will ream the inside of casing  14  to diameters D 110 , D 130 . However, within casing  14 , reamer sections  110 ,  130  do not rotate about axis  105 ; within casing  14 , reamer sections  110 ,  130  are forced to rotate about aligned axes  15 ,  105 ′. More specifically, cutting elements  150  are mounted to the blade&#39;s  111  distal leading ends  140   b  disposed at radius R 111max , and cutting elements  150  are mounted to the blade&#39;s  131  distal leading ends  140   a  disposed at radius R 131max . Engagement of the smooth formation facing surfaces  141  disposed at radii R 111max , R 131max  at leading ends  140   b ,  140   a , respectively, with the smooth inner cylindrical surface of casing  14  continuously forces reamer sections  110 ,  130  to rotate about axes  15 ,  105 ′ and prevents cutting faces  153  from cutting into casing  14 . Since eccentric reamer sections  110 ,  130  are forced to rotate about axes  15  of casing  14 , the rotational diameter of reamer sections  110 ,  130  within casing  14  are equal to pass through diameters D 110 , D 130 , thereby enabling tool  100  and reamer sections  110 ,  130  to pass axially through casing  14  while being rotated and without reaming or damaging casing  14 . 
     Referring now to  FIGS. 1 and 7 , once bit  40  has sufficiently advanced, tool  100  exits the lower end of casing  14 . Once tool  100  is clear of casing  14 , formation facing surfaces  141  on the leading ends  140   b ,  140   a  of blades  111 ,  131 , respectively, no longer slidingly engage the smooth cylindrical inner surface of casing  14 , and thus, reamer sections  110 ,  130  are no longer forced to rotate about casing axes  15 ,  105 ′. Rather, once tool  100  is clear of casing  14 , reamer sections  110 ,  130  rotate about tool axis  105 , thereby enabling reamer sections  110 ,  130  to ream borehole  11  to diameter D 110′ , D 130′ , which is greater than diameters D 14 , D 110 , D 130 . When drilling new sections of borehole  11  (i.e., during advancement of tool  100  through borehole  11 ), downhole reamer section  130  leads uphole reamer section  110  and functions as the primary reamer, whereas when tripping tool  100  out of borehole  11  (i.e., during retraction of tool  100  from borehole  11 ), uphole reamer section  110  leads downhole reamer section  110  and functions as the primary reamer. Cutter elements  150  of downhole reamer section  130  are disposed proximal lower ends  140   b  of blades  131 , and extend to progressively increasing radii moving axially from downhole ends  140   b  toward uphole ends  140   a  of blades  131 ; and cutter elements  150  of uphole reamer section  110  are disposed proximal uphole ends  140   a  of blades  111 , and extend to progressively increasing radii moving axially from uphole ends  140   a  toward lower ends  140   b  of blades  111 . Thus, when drilling new sections of borehole  11 , tool  100  is rotated in cutting direction  106  about axis  105  and downhole reamer section  130  leads uphole reamer section  110 , and more specifically, downhole ends  140   b  lead blades  131  as tool  100  advances axially through borehole  11 , thereby enabling cutter elements  150  mounted to blades  131  to progressively increase the diameter of borehole  11  to diameter D 130′  as downhole reamer section  130  advances through borehole  11 . When tripping tool  100  out of borehole  11 , tool  100  is rotated in cutting direction  106  about axis  105  and uphole reamer section  110  leads downhole reamer section  130 , and more specifically, uphole ends  140   a  lead blades  111  as tool  100  advances axially through borehole  11 , thereby enabling cutter elements  150  mounted to blades  111  to progressively increase the diameter of borehole  11  to diameter D 110′  as uphole reamer section  110  advances through borehole  11 . In the manner described, tool  100  and reamer sections  110 ,  130  can be rotated within casing  14  without cutting or damaging casing  14  and ream borehole  11  to a diameter D 110′ , D 130′  that is greater than the inner diameter D 14  of casing. Within casing  14 , reamer sections  110 ,  130  are forced to rotate about axis  15  of casing  14 , however, once sections  110 ,  130  are clear of casing  14 , reamer sections  110 ,  130  rotate about axis  105  of tool  100 . In addition, tool  100  and reamer sections  110 ,  130  can ream borehole  11  while drilling new sections of borehole  11  and while tripping tool  100  out of borehole  11 . Furthermore, reamer sections  110 ,  130  can be used in connection with a drill bit (e.g., bit  40 ) that is being rotated exclusively by a mud motor. Specifically, because the pass through diameters D 110 , D 130  of the reamer sections  110 ,  130 , respectively, are slightly less than the diameter of the drill bit (e.g., diameter D 40  of drill bit  40 ) which is equal to or slightly less than the casing diameter (e.g., diameter D 14 ), reamer sections  110 ,  130  can pass through a borehole (e.g., borehole  11 ) that is being drilled by the bit (e.g., bit  40 ) without also rotating therein. 
     In the embodiment of tool  100  previously shown and described, reamer sections  110 ,  130  are axially spaced apart along a single body  101 . However, in other embodiments, the reamer sections (e.g., reamer sections  110 ,  130 ) can be disposed on different tubulars, tools, or bodies. For example, the lower reamer section (e.g., reamer section  130 ) can be disposed on a first tubular body axially adjacent the drill bit (e.g., bit  40 ) and the uphole reamer section (e.g., reamer section  130 ) can be disposed on a second tubular body axially adjacent and coupled to the first tubular body. Still further, in drillstring  30  previously shown and described, bit  40  is a separate component that is removably coupled to tool  100  including reamer sections  110 ,  130 . However, in other embodiments, the bit (e.g., bit  40 ) and one or both reamer sections (e.g., lower reamer section  110  or reamer sections  110 ,  130 ) can be integrally formed as a single component or tool. Moreover, although drill bit  40  coupled to reamer sections  110 ,  130  is a fixed cutter bit, in other embodiments, the reamer sections (e.g., reamer sections  110 ,  130 ) can be used in connection with different types of drill bit such as rolling cone drill bits. Also, in the embodiment of tool  100  previously shown and described, reamer sections  110 ,  130  are disposed within a recess  104  positioned along the outer surface  102  of body  101 . However, in other embodiments, no such recess  104  may be included. Further, in other embodiments, the recess  104  may be included along the outer surface  102  of the body  101 , but the recess  104  may not be equidistant from the ends  101   a ,  101   b . Still further, although the upper end  101   a  of the body  101  of tool  100  has been shown and described as having a female box end  107 , and the lower end  101   b  has been shown and described as having a male pin end  108 , in other embodiments, the upper end  101   a  may have a male pin end and/or the lower end  101   b  may have a female box end. Moreover, in some embodiments, the drill bit  40  may have a male pin end type connector. 
     While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.