EP1039095B1 - Trépan de forage - Google Patents

Trépan de forage Download PDF

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Publication number
EP1039095B1
EP1039095B1 EP00302231A EP00302231A EP1039095B1 EP 1039095 B1 EP1039095 B1 EP 1039095B1 EP 00302231 A EP00302231 A EP 00302231A EP 00302231 A EP00302231 A EP 00302231A EP 1039095 B1 EP1039095 B1 EP 1039095B1
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EP
European Patent Office
Prior art keywords
section
tool
upsets
bit
reamer
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Expired - Lifetime
Application number
EP00302231A
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German (de)
English (en)
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EP1039095A2 (fr
EP1039095A3 (fr
Inventor
Coy M. Fielder
Rogerio H. Silva
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
ReedHycalog LP
Original Assignee
Diamond Products International Inc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Diamond Products International Inc filed Critical Diamond Products International Inc
Publication of EP1039095A2 publication Critical patent/EP1039095A2/fr
Publication of EP1039095A3 publication Critical patent/EP1039095A3/fr
Application granted granted Critical
Publication of EP1039095B1 publication Critical patent/EP1039095B1/fr
Anticipated expiration legal-status Critical
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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00—Drill bits
    • E21B10/26—Drill bits with leading portion, i.e. drill bits with a pilot cutter; Drill bits for enlarging the borehole, e.g. reamers
    • E21B10/265—Bi-center drill bits, i.e. an integral bit and eccentric reamer used to simultaneously drill and underream the hole

Definitions

  • the present invention is directed to downhole tools. More specifically, the present invention is directed to a stabilized bi-center drill bit and methods for its manufacture.
  • a significant source of many drilling problems relates to drill bit and string instability, of which there are many types. Bit and/or string instability probably occurs much more often than is readily apparent by reference to immediately noticeable problems. However, when such instability is severe, it places high stress on drilling equipment that includes not only drill bits but also downhole tools and the drill string in general. Common problems caused by such instability may include, but are not limited to, excessive torque, directional drilling control problems, and coring problems.
  • one presently commercially available drill bit includes reinforced polycrystalline diamond compact ("PDC") members that are strengthened by use of a fairly large taper, or frustoconical contour on the PDC member.
  • the taper angle is smaller than the backrake angle of the cutter to allow the cutter to cut into the formation at a desired angle.
  • PDC polycrystalline diamond compact
  • this design makes the PDC cutters stronger so as to reduce cutter damage, it does not solve the primary problem of bit instability.
  • drill string problems, directional drilling control problems, and excessive torque problems remain.
  • the PDC diamond table must be ground on all of the PDC cutters, the drill bits made in this manner are more expensive and less resistant to abrasive wear as compared to the same drill bit made with standard cutters.
  • bit whirl is a very complicated process that includes many types of bit movement patterns or modes of motion wherein the bit typically does not remain centered within the borehole.
  • the solution is based on the premise that it is impossible to design and build a perfectly balanced bit. Therefore, an intentionally imbalanced bit is provided in a manner that improves bit stability.
  • One drawback to this method is that for it to work, the bit forces must be the dominant force acting on the bit.
  • the bits are generally designed to provide for a cutting force imbalance that may range about 500 to 2000 pounds depending on bit size and type. Unfortunately, there are many cases where gravity or string movements create forces larger than the designed cutting force imbalance and therefore become the dominant bit forces. In such cases, the intentionally designed imbalance is ineffective to prevent the bit from becoming unstable and whirling.
  • Penetration limiters work to prevent excessive cutter penetration into the formation that can lead to bit whirl or cutter damage. These devices may act to prevent not only bit whirl but also prevent radial bit movement or tilting problems that occur when drilling forces are not balanced.
  • penetration limiters should preferably satisfy two conditions. Conventional wisdom dictates that when the bit is drilling smoothly (i.e., no excessive forces on the cutters), the penetration limiters must not be in contact with the formation. Second, if excessive loads do occur either on the entire bit or to a specific area of the bit, the penetration limiters must contact the formation and prevent the surrounding cutters from penetrating too deeply into the formation.
  • Prior art penetration limiters are positioned behind the bit to perform this function.
  • the prior art penetration limiters fail to function efficiently, either partially or completely, in at least some circumstances. Once the bit becomes worn such that the PDC cutters develop a wear flat, the prior art penetration limiters become inefficient because they begin to continuously contact the formation even when the bit is drilling smoothly. In fact, a bit with worn cutters does not actually need a penetration limiter because the wear flats act to maintain stability. An ideal penetration limiter would work properly when the cutters are sharp but then disappear once the cutters are worn.
  • Bi-center bits have been used sporadically for over two decades as an alternative to undereaming.
  • a desirable aspect to the bi-center bit is its ability to pass through a small hole and then drill a hole of a greater diameter.
  • Problems associated with the bi-center bit include those of a short life due to irregular wear patterns and excessive wear, the creation of a smaller than expected hole size and overall poor directional characteristics.
  • the bi-center bit has yet to realize its potential as a reliable alternative to undereaming.
  • EP 0058061 discloses a tool for an underground formation.
  • the tool is an eccentric hole opener and has eccentric portion, the interface of which has cutting elements, such as poly-crystalline diamond compacts.
  • the tool thus has a body with a proximal end adapted for connection to a drill string and distal end which defines a pilot section. There is an intermediate reamer section which has a greater diameter than the pilot section.
  • the present invention seeks to provide an improved downhole tool and an improved method of fabricating a downhole tool.
  • a downhole tool comprising a body defining a proximal end adapted for connection to a drill string and a distal end and where said distal end defines a pilot section and an intermediate reamer section and where both the pilot section and reamer section are provided with upsets in the form of ribs or blades each having a plurality of cutting elements defining cutting surfaces and where the body defines a rotational diameter and a pass-through diameter wherein that stabilising wings are coupled to said body opposite said reamer section or said pilot section.
  • the stabilising wings define the outer diametrical extend of the tool.
  • the stabilising wings are provided with cutting elements having a backrake angle in the range of 25°- 75°.
  • stabilising wings define a radial length which is determined as a function of the outside diameter of the tool.
  • the radial length is defined as the difference between the outside diameter of the pilot section and the pass-through diameter of the tool.
  • said stabilising wings is provided with high angle cutting elements.
  • the pass-through diameter is defined by two upsets of the reamer, termed the leading and trailing upsets, and one further point on the body, the cutting elements on the leading and trailing upsets defining a backrake angle of between 25° and 75° with the formation.
  • the reamer section comprises a plurality of upsets radiating from the tool axis about a selected portion of the tool when viewed in cross section, and the stabilising wings comprise a plurality of wings which extend from the body opposite said upsets.
  • the stabilising wings have a mass selected to offset imbalance forces created by the reamer section on rotation of the tool.
  • the invention also provide a method of fabricating a downhole tool, said downhole tool comprising a body defining a proximal end adapted for connection to a drill string and a distal end, where the distal end defines a pilot section and an intermediate reamer section, and where both the pilot section and reamer section are provided with upsets in the form of ribs or blades each having a plurality of cutting elements defining cutting surfaces and where the body defines a rotational diameter and a pass-through diameter, wherein stabilising wings provided on said body opposite said reamer or said pilot section, the upsets of the pilot section and the reader section being disposed around a rotational axis "A" and a pass-through axis "B", the method comprising:
  • a preferred embodiment of the invention includes a pilot bit having a hard metal body defining a proximal end adapted to be operably coupled to the drill string, and an end face provided with a plurality of cutting elements, and a reamer section integrally formed on one side of the body between the proximal end and the end face.
  • the resulting bi-center bit is adapted to be rotated in the borehole in a generally conventional fashion to create a hole of a larger diameter than through which it was introduced.
  • the pilot bit diameter is typically the same size as the max tool size.
  • the max tool size is a diameter determined by the tools that are to be used directly above the bit and generally correspond to common motor diameters (this is a known factor in designating bi-center bits).
  • the pilot bit is reduced in diameter by an amount that relates to the amount force required to improve the design (smaller pilot equals more force that can be directed to the reamer).
  • the wings that are added are designed to drill the formation that is encountered between the reduced pilot diameter and the max tool diameter. Since a smaller pilot results in larger wings and it is the cutters on the wing that creates the force direct at the primary reamer blades then a smaller pilot gives us the ability to direct more force towards the reamer.
  • Figures 1-7 generally illustrate a conventional bi-center bit and its method of operating in the borehole.
  • bit body 2 manufactured from steel or other hard metal, includes a threaded pin 4 at one end for connection in the drill string, and a pilot bit 3 defining an operating end face 6 at its opposite end.
  • a reamer section 5 is integrally formed with the body 2 between the pin 4 and the pilot bit 3 and defines a second operating end face 7, as illustrated.
  • operating end face includes not only the axial end or axially facing portion shown in Figure 2, but also contiguous areas extending up along the lower sides of the bit 1 and rcamer 5.
  • bit 3 The operating end face 6 of bit 3 is transversed by a number of upsets in the form of ribs or blades 8 radiating from the lower central area of the bit 3 and extending across the underside and up along the lower side surfaces of said bit 3.
  • Ribs 8 carry cutting members 10, as more fully described below.
  • bit 3 defines a gauge or stabilizer section, including stabilizer ribs or gauge pads 12, each of which is continuous with a respective one of the cutter carrying rib 8.
  • Ribs 8 contact the walls of the borehole that has been drilled by operating end face 6 to centralize and stabilize the tool 1 and to help control its vibration. (See Figure 4).
  • the pass-through diameter of the bi-center is defined by the three points where the cutting blades are at gauge. These three points are illustrated at Figure 2 are designated “x,” “y” and “z.”
  • Reamer section 5 includes two or more blades 11 which are eccentrically positioned above the pilot bit 3 in a manner best illustrated in Figure 2. Blades 11 also carry cutting elements 10 as described below. Blades 11 radiate from the tool axis but are only positioned about a selected portion or quadrant of the tool when viewed in end cross section.
  • the tool 1 may be tripped into a bore hole having a diameter marginally greater than the maximum diameter drawn through the reamer section 5, yet be able to cut a drill hole of substantially greater diameter than the pass-through diameter when the tool 1 is rotated about the geometric or rotational axis "A.”
  • the axis defined by the pass-through diameter is identified at "B.” (See Figures 4A-B.)
  • cutting elements 10 are positioned about the operating end face 7 of the reamer section 5.
  • reamer section 5 defines a gauge or stabilizer section, including stabilizer ribs or gauge pads 17, each of which is continuous with a respective one of the cutter carrying rib 11.
  • Ribs 11 contact the walls of the borehole that has been drilled by operating end face 7 to further centralize and stabilize the tool 1 and to help control its vibration.
  • a shank 14 having wrench flats 15 that may be engaged to make up and break out the tool 1 from the drill string (not illustrated).
  • the underside of the bit body 2 has a number of circulation ports or nozzles 15 located near its centerline. Nozzles 15 communicate with the inset areas between ribs 8 and 11, which areas serve as fluid flow spaces in use.
  • each of the ribs 8 and 11 has a leading edge surface 8A and 11A and a trailing edge surface 8B and 11B, respectively.
  • each of the cutting members 10 is preferably comprised of a mounting body 20 comprised of sintered tungsten carbide or some other suitable material, and a layer 22 of polycrystalline diamond carried on the leading face of stud 38 and defining the cutting face 30A of the cutting member.
  • the cutting members 10 are mounted in the respective ribs 8 and 11 so that their cutting faces are exposed through the leading edge surfaces 8A and 11, respectively.
  • cutting members 10 are mounted so as to position the cutter face 30A at an aggressive, low angle, e.g., 15-20° backrake, with respect to the formation. This is especially true of the cutting members 10 positioned at the leading edges of bit body 2.
  • Ribs 8 and 11 are themselves preferably comprised of steel or some other hard metal.
  • the tungsten carbide cutter body 38 is preferably brazed into a pocket 32 and includes within the pocket the excess braze material 29.
  • the conventional bi-center bit normally includes a pilot section 3 which defines an outside diameter at least equal to the diameter of bit body 2. In such a fashion, cutters on pilot section 3 may cut to gauge. (See Figure 3.)
  • FIG. 8 illustrates a side view of a preferred embodiment of the bi-center bit 30 of the present invention.
  • the bit 30 comprises a bit body 32 which includes a threaded pin at one end 34 for connection to a drill string and a pilot bit 33 defining an operating end face 36 at its opposite end.
  • a reamer section 35 is integrally formed with body 32 between the pin 34 and pilot bit 33 and defines a second operating end face 37.
  • the operating end face 36 of pilot 33 is traversed by a number of upsets in the form of ribs and blades 38 radiating from the central area of bit 33.
  • ribs 38 carry a plurality of cutting members 40.
  • the reamer section 35 is also provided with a number of blades or upsets 42, which upsets are also provided with a plurality of cutting elements 40 which themselves define cutting faces.
  • the general embodiment illustrated in Figure 8-9 is provided with a pilot section 33 defining a smaller cross sectional diameter than the conventional embodiment illustrated in Figures 1-7.
  • the extent to which the pilot is smaller is determined as a function of the force improvement needed in the direction opposite the pilot 33.
  • pilot 33 defines a bald or bare spot 44 where cutters 40 have been removed.
  • Spot 44 is defined about an upset located about the midpoint of the arc defined by the reamer section 35.
  • the purpose of removing cutters from this area of the pilot 33 is to lessen the forces about this upset on the pilot 33 toward wings 50, as will be described further below.
  • Area 44 is created by removing cutter 40 situated in an area between 90 and 45 degrees along the upset as viewed in cross section.
  • bit 30 may be provided with stabilizer wings 50 opposite reamer section 35.
  • Wings 50 may be secured to bit body 32 in a conventional fashion, e.g. , welding, or may be formed integrally. Wings 50 serve to define the outer diametrical extent of tool 30 opposite pilot 33. (See Figure 8.) Wings 50 are preferably provided with cutters 42 having a backrake angle in the range of 25-75°.
  • the length of wings 50 is a function of the outside diameter of the tool 30 as a whole. In this connection, it is desired that this length, identified as L 2 in Figure 9, be the difference between the outside diameter of the pilot 33 and the pass through diameter of the tool 30. Alternately, wings 50 may adopt a length intermediate the pass-through differential.
  • Wings 50 may be axially situated approximately opposite reamer section 35, as illustrated. Alternatively, wings 50 may be disposed about pilot section 33, the goal being to offset imbalance forces created by reamer section 35. In this connection, wings 50 can be affixed on the reamer 35 or pilot 33.
  • the use of a high imbalance is substantially meaningless on drill bits (non bi-centers) and has thus not been considered since it was thought to be impossible to accomplish on a bi-center.
  • the force balancing method of the present invention makes this a possibility and provides significant improvement over a low imbalance. The key is that the higher force imbalance would be directed towards the pilot.
  • a force imbalance of 12.29% is the result of reducing the pilot diameter and adding wings opposite the primary reamer blades. (High angle cutters are not used in this example.) This is similar to bits produced in the past using a smaller pilot and wings. Although this number is better, it is far from what is considered acceptable. By changing the wing cutters from normal angle to high angle cutters, the imbalance drops to 7.5%. (Calculated results not shown.) For the preferred method in the invention disclosure containing all four steps, smaller pilot, wings, high angle cutters on the wings and the removal of cutters on one side of the pilot. The result here is 4.41 %, which is now in the "good" range of values.
  • the bi-center bit of the present invention may enjoy a number of adaptations.
  • One such adaptation is an embodiment to drill through a casing shoe, such as is illustrated in Figures 11-12.
  • pilot section 103 defining a smaller cross-sectional diameter than the conventional embodiment illustrated in Figures 1-7.
  • the use of a lesser diameter for pilot section 103 serves to minimize the opportunity for damage to the borehole or casing when the tool 100 is rotated about the pass-through axis "B.”
  • cutters 110 which extend to gauge generally include a low backrake angle for maximum efficiency in cutting. (See Figure 1.)
  • cutters 110 on the leading and trailing blades 118 at gauge define a backrake angle of between 25-75 degrees with the formation.
  • the method by which the shoe cutter embodiment of the bi-center bit of the present invention may be constructed may be described as follows.
  • a cutter profile is established for the pilot bit.
  • the pass-through axis is the then determined from the size and shape of the tool.
  • a cutter profile of the tool is made about the pass-through axis. This profile will identify any necessary movement of cutters 110 to cover any open, uncovered regions on the cutter profile. These cutters 110 may be situated along the primary upset 131 or upsets 132 radially disposed about geometric axis "A.” (See Figure 15.)
  • cutters 110 must be oriented in a fashion to optimize their use when tool 100 is rotated about both the pass-through axis "B" and geometric axis "A.”
  • cutters 110 positioned for use in a conventional bi-center bit will be oriented with their cutting surfaces oriented toward the surface to the cut, e.g. , the formation.
  • cutters 110 so oriented on the primary upset 131 in the area 110 between axes "A" and “B” will actually be oriented 180° to the direction of cut when tool 100 is rotated about pass-through axis "B.”
  • Cutters 110 disposed along primary upset 131 outside of region 110 in region 141 are oriented such that their cutting faces 130A are brought into at least partial contact with the formation regardless of the axis of rotation. Cutters 110 oppositely disposed about primary upset 131 in region 142 are oriented in a conventional fashion. (See Figure 15.)
  • Cutters 110 not situated on primary upset 131 oriented are disposed on radial upsets 132. These cutters 110, while their positioning may be dictated by the necessity for cutter coverage when tool 100 is rotated about axes "A" and "B," as described above, are oriented on their respective upsets 132 or are skewed to such an angle such that at least twenty percent of the active cutter face 130 engages the formation when the bi-center bit is rotated about axis "A.” Restated as a function of direction of cut, the skew angle of cutters 110 is from 0°-80°.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Mechanical Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)
  • Drilling Tools (AREA)

Claims (10)

  1. Trépan de forage comprenant un corps (32) définissant une extrémité proximale (34) adaptée en vue d'une connexion à un train de forage, et une extrémité distale, et dans lequel ladite extrémité distale définit une section pilote (33) et une section d'alésage intermédiaire (35), et dans lequel la section pilote (33) et la section d'alésage (35) sont toutes deux pourvues de parties redressées sous la forme de nervures ou de lames (38, 42) ayant chacune une pluralité d'éléments de coupe (40) définissant des surfaces de coupe, et dans lequel le corps définit un diamètre de rotation et un diamètre de passage, caractérisé en ce que des ailettes de stabilisation (50) sont couplées audit corps à l'opposé de ladite section d'alésage (35), ou de ladite section pilote (33).
  2. Trépan de forage selon la revendication 1, dans lequel les ailettes de stabilisation (50) définissent l'extension de diamètre extérieur de l'outil.
  3. Trépan de forage selon l'une ou l'autre des revendications 1 et 2, dans lequel les ailettes de stabilisation sont pourvues d'éléments de coupe (40) ayant un angle de dépouille postérieure dans la plage de 25 à 75°.
  4. Trépan de forage selon l'une quelconque des revendications précédentes, dans lequel lesdites ailettes de stabilisation (50) définissent une longueur radiale qui est déterminée en fonction du diamètre extérieur de l'outil.
  5. Trépan de forage selon la revendication 4, dans lequel la longueur radiale est définie comme étant la différence entre le diamètre extérieur de la section pilote (33) et le diamètre de passage de l'outil (32).
  6. Trépan de forage selon l'une quelconque des revendications précédentes, dans lequel lesdites ailettes de stabilisation (50) sont pourvues d'éléments de coupe (40) présentant un angle important.
  7. Trépan de forage selon l'une quelconque des revendications précédentes, dans lequel le diamètre de passage est défini par deux parties redressées de la section d'alésage, appelées la partie redressée de tête et la partie redressée de queue, et l'une d'elles étant en outre pointée vers le corps, lesdits éléments de coupe sur la partie redressée de tête et sur la partie redressée de queue définissant un angle de dépouille postérieure entre 25 et 75° avec la formation.
  8. Trépan de forage selon l'une quelconque des revendications précédentes, dans lequel la section d'alésage (35) comprend une pluralité de parties redressées (42) qui rayonnent depuis l'axe de l'outil autour d'une portion choisie de l'outil lorsqu'on l'observe en section transversale, et les ailettes de stabilisation (50) comprennent une pluralité d'ailettes (50) qui s'étendent depuis le corps à l'opposé desdites parties redressées.
  9. Trépan de forage selon l'une quelconque des revendications précédentes, dans lequel les ailettes de stabilisation (50) ont une masse choisie pour effectuer un déséquilibrage avec décalage des forces engendrées par la section d'alésage sur la rotation de l'outil.
  10. Procédé pour fabriquer un trépan de forage, ledit trépan de forage comprenant un corps (32) définissant une extrémité proximale (34) adaptée en vue d'une connexion à un train de forage, et une extrémité distale, dans lequel extrémité distale définit une section pilote (33) et une section d'alésage intermédiaire (35), et dans lequel la section pilote (33) et la section d'alésage (35) sont toutes deux pourvues de parties redressées sous la forme de nervures ou de lames (38, 42) ayant chacune une pluralité d'éléments de coupe (40) définissant des surfaces de coupe, et dans lequel le corps définit un diamètre de rotation et un diamètre de passage, des ailettes de stabilisation (50) étant prévues sur ledit corps à l'opposé de ladite section d'alésage (35) ou de ladite section pilote (33), les parties redressées (38, 42) de la section pilote (33) et de la section d'alésage (35) étant disposées autour d'un axe de rotation "A" et d'un axe de passage "B", le procédé comprenant les étapes consistant à :
    établir un axe de passage pour l'outil ;
    créer un profil de coupe pour la section pilote autour de l'axe de passage ;
    situer les éléments de coupe sur les parties redressées pour couvrir des régions ouvertes identifiées dans le profil de coupe ;
    positionner les parties redressées en évaluant la distance de chaque élément de coupe donné depuis l'axe de passage "B" et l'axe de rotation "A" ; et
    orienter les éléments de coupe pour optimiser leur utilisation quand l'outil est mis en rotation soit autour de l'axe "A" soit autour de l'axe "B", de sorte que les faces de coupe des éléments de coupe sont amenées en contact au moins partiel avec la formation.
EP00302231A 1999-03-19 2000-03-20 Trépan de forage Expired - Lifetime EP1039095B1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US12511999P 1999-03-19 1999-03-19
US125119 1999-03-19

Publications (3)

Publication Number Publication Date
EP1039095A2 EP1039095A2 (fr) 2000-09-27
EP1039095A3 EP1039095A3 (fr) 2001-04-11
EP1039095B1 true EP1039095B1 (fr) 2005-05-18

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EP00302231A Expired - Lifetime EP1039095B1 (fr) 1999-03-19 2000-03-20 Trépan de forage

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DE (1) DE60020185T2 (fr)

Families Citing this family (10)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6269893B1 (en) * 1999-06-30 2001-08-07 Smith International, Inc. Bi-centered drill bit having improved drilling stability mud hydraulics and resistance to cutter damage
US6659207B2 (en) * 1999-06-30 2003-12-09 Smith International, Inc. Bi-centered drill bit having enhanced casing drill-out capability and improved directional stability
GB2376489B (en) * 1999-06-30 2003-05-28 Smith International Bi-centre drill bit
US6394200B1 (en) 1999-10-28 2002-05-28 Camco International (U.K.) Limited Drillout bi-center bit
GB0820063D0 (en) 2008-11-03 2008-12-10 Reedhycalog Uk Ltd Drilling tool
US8327957B2 (en) * 2010-06-24 2012-12-11 Baker Hughes Incorporated Downhole cutting tool having center beveled mill blade
US8851205B1 (en) 2011-04-08 2014-10-07 Hard Rock Solutions, Llc Method and apparatus for reaming well bore surfaces nearer the center of drift
US9739094B2 (en) * 2013-09-06 2017-08-22 Baker Hughes Incorporated Reamer blades exhibiting at least one of enhanced gage cutting element backrakes and exposures and reamers so equipped
US11111739B2 (en) 2017-09-09 2021-09-07 Extreme Technologies, Llc Well bore conditioner and stabilizer
WO2019075076A1 (fr) 2017-10-10 2019-04-18 Extreme Technologies, Llc Systèmes et dispositifs d'alésage de trou de sonde

Family Cites Families (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
FR1249499A (fr) * 1959-11-19 1960-12-30 Europ De Turboforage Soc équipement pour le forage du sol
EP0058061A3 (fr) * 1981-02-07 1982-09-01 DRILLING & SERVICE U.K. LIMITED Outil de forage pour formation souterraine
US5678644A (en) * 1995-08-15 1997-10-21 Diamond Products International, Inc. Bi-center and bit method for enhancing stability
US6164394A (en) * 1996-09-25 2000-12-26 Smith International, Inc. Drill bit with rows of cutters mounted to present a serrated cutting edge
US5765653A (en) * 1996-10-09 1998-06-16 Baker Hughes Incorporated Reaming apparatus and method with enhanced stability and transition from pilot hole to enlarged bore diameter

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Publication number Publication date
DE60020185T2 (de) 2006-01-12
DE60020185D1 (de) 2005-06-23
EP1039095A2 (fr) 2000-09-27
EP1039095A3 (fr) 2001-04-11

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