• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
  • 同族专利
  • 引用文献
  • 法律状态
  • 优先权
    • 专利摘要:
    The present invention relates to a drill hole that can be drilled using the bottom hole assembly 10, 50 with a wellbore motor 14, 110, which can be displaced at a selected angle of curvature. A bend for directional drilling can be provided by a pdm1 or an rsd. a calibration section 36 attached to the pilot drill 18 has a bearing surface of uniform diameter along an axial length of at least 60% of the pilot drill diameter. drill or countersink 16 has a drill face defining the cutting diameter of the drilled hole. The axial spacing between the curvature and the drill face is controlled to less than fifteen times the drill diameter. The wellbore motor, pilot drill and drill can be recovered from the well while leaving the casing tubing in the well.
    公开号:BR0317401C1
    申请号:RC10317401
    申请日:2003-12-10
    公开日:2018-05-15
    发明作者:D Chen Chen-Kang；M Rao Vikram
    申请人:Halliburton Energy Services Inc；
    IPC主号:
    专利说明:

    (54) Title: DRILLING WITH COATING (51) Int.CI .: E21B 7/08 (30) Unionist Priority: 11/04/2005 US 11 / 103,186 (73) Holder (s): HALLIBURTON ENERGY SERVICES, INC (72 ) Inventor (s): CHEN-KANG D. CHEN; VIKRAM M. RAO
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    METHOD AND SYSTEM FOR DRILLING A WELL HOLE Certificate of Addition of Invention of PI0317401-8, deposited on December 10, 2003.
    Addition Certificate Field [0001] This addition certificate refers to the technology for drilling a gas or oil well, with the casing column remaining inside the well after drilling. More specifically, the present certificate of addition refers to techniques to improve the drilling efficiency of a coated well, with improved well quality providing better hydrocarbon recovery, and with technology allowing significantly reduced costs to reliably complete the process. well.
    Background to the Certificate of Addition [0002] Most hydrocarbon wells are drilled in successively smaller coating sections, with a coating of selected size inserted in a perforated section before drilling the next lower diameter section of the well, then inserting a reduced diameter casing size in the lower section of the well. The depth of each perforated section is thus a function of (1) the operator's desire to continue drilling as deep as possible before stopping the drilling operation and inserting the liner into the perforated section, (2) the risk that formations upper parts are damaged by the high pressure fluid required to obtain desired well balance powder and the well bore fluid pressure at greater depths, and (3) the risk that a portion of the drilled well may collapse or otherwise prevent coating to be inserted into the well, or that the coating becomes attached to the well or otherwise be practically prevented from being inserted into the desired depth in a well.
    [0003] To avoid the above problems, several techniques for drilling a well with a coating have been proposed. This technique inherently
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    2/28 inserts the liner into the well with the well bottom composition (BHA) while the well, or a section of the well, is being drilled. U.S. Patents 3,552,509 and 3,661,218 describe drilling with rotary coating techniques. U.S. Patent 5,168,942 describes a technique for drilling a coated well, with the well-bottom composition including the ability to sense the resistivity of the perforated formation. U.S. Patent 5,197,533 also describes a technique for drilling a well with a liner. U.S. Patent 5,271,472 describes yet another technique for drilling the coated well, and specifically describes using a reamer to drill a portion of the well with a diameter larger than the OD of the coating. US Patent 5,472,051 describes a coated well, with a downhole composition including a drill motor to rotate the drill, thereby allowing the operator at the surface (a) to rotate the coating and thereby mill the drill, or (b) rotate the bit with fluid transmitted through the drill motor and into the bit. Yet another option is to rotate the coating on the surface and simultaneously activate the drill motor to rotate the drill. U.S. Patent 6,118,531 describes a coating drilling technique that uses a mud motor at the end of the spiral pipe to rotate the drill. SPE 52789, 62780 and 67731 papers discuss the commercial advantages of coating drilling in terms of lower well costs and improved drilling processes.
    [0004] Problems, however, limited the acceptance of coating drilling operations, including the cost of coating capable of transmitting high torque from the surface to the drill, high losses between the applied surface torque and the torque on the drill, high coating wear, and difficulties associated with recovering the drill and the drill motor to the surface through the coating.
    [0005] The disadvantages of the prior art are overcome by the present certificate of addition, and the improved coating drilling methods are hereinafter described, which will result in a
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    3/28 coating inserted into a well during a coating drilling operation, with lower costs and improved well quality providing lower cost and / or increased hydrocarbon recovery.
    Summary of Certificate of Addition [0006] This certificate of addition provides coated drilling, in which a well is drilled using a downhole composition at the bottom end of the coating column and a borehole motor with a bending angle selected, such that the pilot drill and reamer (or bicentre drill) when rotated by the engine have a geometry axis displaced at a selected bending angle from the geometry axis of the engine power section. According to the addition certificate, the motor housing can be smooth, meaning that the motor housing has an outer surface of substantially uniform diameter extending axially from the upper power section to the lower bearing section. The motor can be a positive displacement motor (PDM) with a bend in the housing, or it can be a rotary steerable device (RSD) with a cylindrical housing and a bend in the rotating rod. RSD can be driven from the surfaces, but more preferably it will be driven by a PDM without a bend in the housing (straight PDM), with the rotation being optimally supplemented by rotation of the coating column. A calibration section is provided attached to the pilot drill, and has a surface of uniform diameter over an axial length of at least about 60% of the drill diameter. The reamer can thus be rotated by rotating the coating column on the surface, but it can also be rotated by pressurized fluid passing through the borehole motor to rotate the pilot drill and reamer. The casing column remains in the well and the well-hole motor, pilot drill and reamer can be recovered from the well.
    [0007] It is an aspect of the certificate of addition that the pilot drill can be rotated with the casing column to drill a section
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    4/28 relatively straight from the wellhead, and that the wellhead motor can be driven to rotate the pilot drill with respect to the non-rotating casing column to drill a deviated part of the wellhead.
    [0008] Another aspect of the addition certificate is that the calibration section attached to the pilot drill can have an axial length of at least 75% of the pilot drill diameter.
    [0009] Yet another aspect of the addition certificate is that the interconnection between the borehole motor and the two-way reamer or drill is preferably carried out with a pin connection at the lower end of the borehole motor and a box connection at the top end of the reamer.
    [00010] A significant aspect of this certificate of addition is that the coating while drilling operations can be carried out with downhole composition, with the coating column using relatively standard connections, such as API coupling connections, instead of special connections required for the coating while drilling operations using a conventional downhole composition.
    [00011] Another aspect of this certificate of addition is that the downhole composition significantly reduces the risk of grabbing the liner in the well, which can cost a drilling operation of tens of thousands of dollars.
    [00012] An advantage of the present certificate of addition is that the downhole composition does not require specially made components. Each component of the downhole composition can be selected by the operator when desired to achieve the objectives of the addition certificate.
    [00013] These and other objectives, aspects and advantages of this certificate of addition will become evident from the following detailed description, in which reference is made to the figures in the attached drawings.
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    5/28
    Brief Description of the Drawings [00014] Figure 1 in general illustrates a drilled well with a downhole composition at the bottom end of a casing column and a borehole motor with a bend, a reamer and a pilot drill.
    [00015] Figure 2 illustrates in more detail a pilot drill, a calibration section attached to the pilot drill, and an reamer.
    [00016] Figure 3 illustrates a pilot drill, and a calibration section attached to the pilot drill, and a bicentre drill.
    [00017] Figure 4 illustrates a box connection on the reamer connected with a pin connection on the motor.
    [00018] Figure 5 illustrates a well-hole motor without bending, but with a reamer and a pilot drill.
    [00019] Figure 6 illustrates a low-cost casing connector for use along the casing column.
    [00020] Figure 7 illustrates an API sheath connector for use along the sheath column.
    [00021] Figure 8 shows a rotatable steering device within a fold on the rotating rod.
    Detailed Description of Preferred Modalities [00022] Figure 1 in general illustrates a well drilled with a downhole composition (BHA) 10 at the bottom of a coating column 12. BHA 10 includes a well driven motor fluid 14 with a bend to rotate a drill 16 to drill a deviated part of the well. A straight section of the well can be drilled by additionally rotating the casing column 12 on the surface to rotate the drill bit 16, which as explained subsequently can be either a reamer or a bicentre drill. To drill a curved section of the borehole, the casing is slid (non-rotating) and the borehole motor 14 rotates drill 16. It is generally desirable to rotate the casing column to minimize the likelihood of the casing column becoming clamped. in the well hole, and
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    6/28 perfect the return of cuts to the surface. In the preferred embodiment, a fold in the downhole composition has a fold angle of less than about 3 degrees.
    [00023] Since the drill bit 16 that drills the well hole has a cutting diameter larger than the OD of the liner, and since the drill bit is recovered through the liner ID after the liner is inserted into the well, the drill bit many applications will be an reamer. The drill bit 16, alternatively, can be a bicentre drill, or any other cutting tool to cut a diameter and well hole larger than the OD of the coating. A pilot drill 18 has a cutting diameter smaller than the liner ID and can be attached to the drill or reamer 16, with the cutting diameter of the reamer, or the bicentre drill, being significantly larger than the cutting diameter of the pilot drill. The well-bore motor 14 can run smoothly, meaning that the motor housing has a substantially uniform diameter from the upper power section 22 through the fold 24 and to the lower bearing section 26. No stabilizer needs to be provided in the motor housing , provided that neither the motor housing nor a small diameter stabilizer is likely to engage the well hole wall due to the large diameter well hole formed by drill 16. The motor housing may include a slider or wear pad. A borehole motor, which uses a lobe rotor, is usually referred to as a positive displacement motor (PDM).
    [00024] The well-hole motor 14 as shown in figure 1, has a fold 24 between the upper shaft 27 of the motor housing and the lower shaft 28 of the motor housing, so that the shaft for the drill 16 is displaced at a selected bending angle of the axis of the lower end of the casing column. The lower bearing section 26 includes a bearing housing assembly that conventionally comprises both thrust and radial bearings.
    [00025] Drill 16, which in many applications will be a reamer, has
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    7/28 a terminal face that is bounded by and defines a drill cut diameter. When the drill bit is a reamer, the reamer will have a face that defines the reamer cutting diameter. In each case, the cutters' faces may lie within a plane substantially perpendicular to the central axis of the drill, as shown in figure 2, or the cutters could be angled, as shown in figure 3. The drill cut diameter, in each case is the diameter of the hole being drilled, and thus the final location of the radially outermost cutter defines the drill cut diameter. The calibration section 34 is below the reamer 16, and is rotatably attached to and / or can be integral with drill 16 and / or pilot drill 18. The axial length of the calibration section (gauge length) is at least 60% the pilot drill diameter is preferably at least 75% of the pilot drill diameter, and in many applications it can be 90% to one and a half times the pilot drill diameter. In a preferred embodiment, the bottom of the calibration section can be in substantially the same axial position as the pilot drill face, but it could be spaced slightly upward from the pilot drill face. The top of the calibration section is preferably only slightly below the cutting face of the drill or reamer 16, although it is preferred that the axial space between the bottom of the calibration section and the pilot drill face is less than the axial spacing between the top of the calibration section and the face of the drill or reamer 16. The diameter of the calibration section may be slightly under-gauge with respect to the pilot drill diameter.
    [00026] The axial length of the calibration section is measured from the top of the calibration section to the front cutting structure of the pilot drill at the lowest point of the pilot drill's full diameter, for example, from the top of the calibration section to the pilot drill cut face. Preferably, not less than 50% of this gauge length forms a cylindrical bearing surface of substantially uniform diameter when rotating with the drill. One or more short spaces or sub-gauge parts can thus be provided between
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    8/28 the top of the calibration section and the bottom of the calibration section. The axial spacing between the top of the calibration section and the pilot drill face will be the total gauge length, and this part which has a rotating cylindrical bearing surface of substantially uniform diameter is preferably not less than about 50% of the length of full caliber. Those skilled in the art will appreciate that the outer surface of the calibration section does not need to be cylindrical, and instead the calibration section is commonly provided with grooves extending along its length, which are typically provided in a spiral pattern. In this embodiment, the calibration section thus has a surface of substantially uniform diameter defined by the cutters in the grooves that form the cylindrical surface therein while rotating. The calibration section can thus have steps or grooves, but the calibration section, however, defines a rotating cylindrical surface. Pilot drill 16 can alternatively use roller cones instead of fixed cutters.
    [00027] Figure 2 shows in more detail a suitable drill bit 16, such as a reamer, which has a cutting diameter 32. Rotatingly fixed to drill bit 16 is a calibration section 34 which has a uniform surface therein providing a surface of cylindrical bearing of uniform diameter over an axial length of at least 60% of the pilot drill diameter, so that the calibration section and the pilot drill 18 together form a long gauge pilot drill. As noted above, the calibration section is preferably integral with the pilot drill, but the calibration section can be formed separately from the pilot drill then rotatably attached to the pilot drill. The reamer 16 would normally be formed separately and then rotatably attached to the calibration section 34, although the reamer body and the calibration section could be formed as an integral body. When the reamer is bicentered at 16, as shown in figure 3, the bicentre drill body is preferably integral with the body of the calibration section 34. The calibration section preferably has a
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    9/28 axial length of at least 75% of the pilot drill diameter. The drill or reamer 16 can be structurally integral with the calibration section 34, or the calibration section can be formed separately and then rotatably attached to the reamer. The drill or reamer 16 includes cutters that move radially outward to a position typically less than, or possibly greater than, 120% of the casing diameter. In many applications, the radially outward position of the cutters in the reamer will be about 115% or less than the coating diameter. The cutters in the reamer 16 can be hydraulically driven to move radially outward in response to an increase in fluid pressure in the downhole composition. Alternatively, an electric wire line intervention can be lowered into the well to move the cutters radially outward and / or radially inward. In still other embodiments, cutters can move radially in response to a J-slot mechanism, or weight on the drill. Figure 3 illustrates a bicenter drill 16 replacing the reamer.
    [00028] Figure 4 represents a box connection 40 provided in the reamer 16 for threaded coupling with the pin connection 42 at the lower end of the borehole motor 14. The preferred interconnection between the motor and the reamer is thus made through a pin connection on the motor and the connection box on the reamer.
    [00029] According to the BHA of this certificate of addition, the first point of contact between the BHA and the wellhead is the pilot drill face, and the second point of contact between the BHA and the wellhead is at along the axial length of the calibration section 34. The third contact point is the drill bit or reamer 16, and the fourth contact point above the borehole motor, and will preferably be along an upper part of the BHA or at the along the coating itself. This fourth point of contact is, however, substantially spaced above the first, second and third points of contact.
    [00030] BHA 10 as shown in figure 1 preferably includes
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    10/28 a MWD tool (measurement during drilling) 40 in the coating column above the engine 14. This is a desirable position for the MWD tool, since it can be less than about 30 meters, and often less than about 25 meters , between the MWD tool and the end of the coating column 12.
    [00031] For the modality of figure 5, the BHA is not used for directional drilling operations, and consequently the motor 14 does not have a bend in the motor housing. The motor is, however, driven to rotate the drill, or the liner itself is usually slid into the well, but it can also be rotated while the motor is driving the drill. BHA 50 as shown in figure 4 can thus be used for substantially straight drilling operations with the benefits discussed above.
    [00032] A significant aspect of this certificate of addition is that BHA allows the use of coating with conventional threaded connectors, such as API (American Petroleum Institute) connectors commonly used in coating operations that do not involve rotation of the coating column. Conventionally, an API 62 connector shown in figure 7 can thus be used to interconnect the cladding joints. This advantage is significant, since then special premium high torque connectors do not have to be supplied in the liner joints or other tubular components of the liner column. The use of conventional components already in stock significantly reduces installation and maintenance costs.
    [00033] As shown in figures 1 to 5, the MWD package 44 is provided below a lower end of the liner 12. The recoverable well bore motor 14 can be driven by passing fluid through the liner, and then into the engine. well bore. The motor 14 can be supported from the casing with a coupling mechanism 51, which absorbs the torque output from the motor 14. The fluid can be diverted through the coupling mechanism, then to the motor and to the reamer and drill. Those skilled in the art
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    11/28 will appreciate that the borehole motor can be engaged on the casing column 12 by various mechanisms, including the plurality of circumferentially arranged hooks 52 that fit into corresponding slots in the casing 12. A plug or other sealing assembly 54 can be provided to seal between the BHA and the cladding column 12. After the hole is drilled, the hooks 52 on the coupling mechanism 51 can be hydraulically activated to move to a release position, and the motor 14, the cutting elements retracted in the drill or reamer 16, the calibration section 34 and the pilot drill 18 can then be recovered to the surface. A recovery tool similar to those used in multilateral systems can be used. Alternatively, reamer cutters can be eliminated or otherwise separated from the reamer body. A casing shoe at the bottom end of the casing column may have the ability to eliminate reamer blades, so that reamer blades can be eliminated instead of retracted, and this option can be used in some applications. In a preferred embodiment, the hollow-hole assembly can be recovered by the line of electrical wires with the liner 12 remaining in the well. Alternatively, a working column can be used to recover the engine.
    [00034] It should be understood that a pilot drill, calibration section, and reamer as discussed above, can be attached to the lower end of the coating column for coating drilling operation when rotating the coating column, which is conventionally rotated when rotating. drills straight sections of the well hole. Significant advantages are, however, realized in many operations to drill at least part of the well with the drill or reamer being driven by a well-hole motor, sometimes with the casing not rotated to allow drilling directionally. During drilling from the length of the well hole to the total depth, TD, the coating may remain in the hole, and the
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    12/28 downhole composition, including the downhole motor, and drill bit returned to the surface for drill repair or replacement. When the full depth of a well is reached, the well hole assembly can similarly be recovered to the surface, although in some applications when TD, the drill, reamer, and pilot drill assembly, or drill assembly is reached and the engine, can remain in the well, and only the MWD assembly recovered to the surface.
    [00035] The BHA in this certificate of addition substantially reduces the torque that must be given to the coating column 12 when drilling a straight section of the well hole. When the casing column 12 is rotated within a well, a significant problem concerns grab-and-go, which causes torque pulses along the casing column when the rotation is momentarily stopped and then restarted. Undesirable grab-and-slide forces are likely to be particularly high at the top of the drill string, where the torque in the wrap column 12 imparted to the surface is greatest. Since the torque given to the casing column 12 in accordance with the present certificate of addition is significantly reduced, the stick-slip consequences of the casing column 12 are similarly reduced, thereby further reducing the requirements for the casing connectors.
    [00036] Using a reduced torque motor in the context of this addition certificate, there is substantially less motor torque and thus also less reverse or reactive torque generated when the drill motor stalls and the drill is suddenly turned by the motor. The high peaks of this variable reverse torque cause torque impulses to propagate upward from the engine to the bottom of the casing column. The lower part of the casing column can therefore briefly wind up when the drill rotation is stopped. The reverse torque is also reduced, allowing for more economical sheath connectors.
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    13/28 [00037] The borehole motor is driven to rotate the drill bit and drill a deflected part of the well, desirably high rates of penetration can often be obtained by rotating the drill bit at less than 350 RPM. The reduced vibrations result from the use of a long gauge above the drill face and the relatively short length between the bend and the drill, thereby increasing the stiffness of the lower bearing section. The benefits of improved well hole quality include reduced hole cleaning expense, improved profile quality and profiling operations, easier coating inserts and safer cementing operations. BHA has low vibration, which again contributes to improved well-hole quality. Drilling with coating techniques is commonly used in a very low percentage of wells. Efforts to improve well hole quality with a BHA are described in US Patent 6,269,892 and would not solve the primary problem with coating drilling operations, which involves the high cost of the coating column due to special connectors, equipment failure due to vibration, and the difficulty of recovering the borehole and drill motor through the casing column. U.S. Patent 6,470,977 describes a downhole composition for countersinking a downhole. This certificate of addition applies technology aimed at a downhole composition that provides significant improvements in well hole quality, but the benefits of improved well hole quality will be secondary to the significant reduction in costs and increased safety to complete. successfully a coating drilling operation.
    [00038] The well hole assembly of this addition certificate is able to drill a hole using less weight in the drill and thus less torque than in prior art BHAs, and is able to drill a more accurate hole with less spiraling. The cladding itself can be thinner walls than the cladding used
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    14/28 in prior art coating drilling operations, or it may have the same wall thickness but can be formed from less expensive materials. The cost of coating suitable for conventional coating drilling operations is high, and forces required to rotate the drill bit to penetrate the formation at a desired drilling rate can be decreased according to this addition certificate, so that less force is transmitted along the casing column for the drill. Since the drilled hole is more accurate, there is less drag on the coating column, and the operator has more flexibility with respect to the weight of the bit to be applied to the surface through the coating column. Since there is less engagement with the borehole wall when the casing slides into the hole with the drill motor being driven to form a deviated part of the borehole, and when the surface casing column rotates to rotate the drill bit when drilling a straight section of the well hole, there is substantially less wear on the liner during the drilling operation, which again allows for a thinner and / or less expensive wall liner.
    [00039] The primary advantage of this certificate of addition is that it allows coating drilling operations to be conducted more economically, and with a lower risk of failure. The most accurate bore produced according to the liner drilling using the present certificate of addition, not only results in less torque and drag in the well, but reduces the likelihood of the coating becoming trapped in the well. Another significant advantage is the increased safety of recovering the drill through the coating column to the surface. As previously noted, the cutting diameter of the drill or reamer must be greater than the OD of the coating, but the drill must be recovered via the coating ID. Several devices have been designed to ensure easy recovery, but all devices are subject to failure, which is largely attributed to the high vibration of BHA. High vibrations for BHA can thus lead to
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    15/28 casing connection, drill failures, and engine failures, and thus adversely affects the safety of the mechanism that requires the drill cut diameter to be reduced to fit within the casing column ID, so that the engine and the drill bit can be recovered to the surface. The relatively smooth wellhead resulting from the BHA of this addition certificate, provides better cementation and hole cleaning. BHA not only results in reduced costs for inserting the casing in the well, but also results in better ROP, better driveability, improved reamer safety, and reduced drilling costs.
    [00040] According to the prior art, a PDM triggering a reamer or bicenter drill and a conventional pilot drill, would be minimally supported radially by the well bore, and thus would be relatively flexible, unbalanced, and therefore inclined to create vibration. Additionally, when this unbalanced assembly is rotated, undesirable grip-slip may be high. Since these torque events would be greater than the nominal torque for standard API sheath joint connections, and since failure of a connection would be a significant cost, prior art sheath drilling used specially designed higher strength sheath connectors , expensive. Prior art casing drilling operations require a high amount of torque to be transmitted to the casing column on the surface in order to overcome the static friction and dynamic friction required to rotate the casing column in the pit when drilling a straight section of the well hole. Frictional losses can be significantly reduced using a downhole composition of this addition certificate, provided that the most accurate downhole resulting from the downhole composition reduces drag between the coating column and the formation.
    [00041] When the liner is being slid (non-rotating from the surface) and the motor is turning to the drill, there is less torque generation required by the motor using this BHA, due to the
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    16/28 pilot drill and calibration section, and the absence of non-constructive drill behaviors. Less aggressive drills and smaller torque motors are therefore preferred. This combination also reduces the reverse torque due to the engine stall. Since a less aggressive drill takes less than a chunk of rock, and since the pilot drill and calibration section result in each chunk being the desired and appropriately targeted chunk, high instant torque and the likelihood of a stall are minimized. If the motor stalls, the low torque motor ensures that the reactive or reverse torque impulse is less, and the reactive torque cannot be any greater than the torque capacity of the motor.
    [00042] When rotating the surface coating to clean the hole, removing directionality, or reducing the possibility of differential gripping, there is less top drive torque being consumed in the interaction between the rotating coating and the wellhead, on the length of the wellhead, due to the wellhead being smoother. The smoothness of the borehole, while primarily impacting the rotating torque, also results in better weight transfer to the drill, allowing the reduced weight to be applied to the surface, and less weight directly on the drill, thereby reducing the depth of cut and the driving action of the cutters. The top drive requires less torque to rotate the casing column, and a much larger proportion of the torque generated by the top drive reaches the drill. The torque that the column elements closest to the surface must transmit, which could otherwise be very high, is reduced, and the sheath connectors may be of lower torque capacity.
    [00043] Figure 8 represents another modality of a BHA according to the present certificate of addition. In one application, a drive source for rotating the drill bit is not a PDM motor, but instead a rotatable steerable device (RSD), with the rotatable steerable housing 112 receiving the rod 114 which is rotated by rotating the casing column on the surface. Various elements of bearing 120,
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    17/28
    374, 372 are axially positioned along the rod 114. Those skilled in the art should understand that the rotatable steering device shown in figure 8 is highly simplified. The drill 360 can include several sensors 366, 368 that can be mounted in an insert package 362 provided with a data port 364. Figure 8 shows the position of a portable MWD system 140 and a drill collar assembly 141.
    [00044] A rotary steerable device (RSD) tilts or applies an off-axis force to the drill in the desired direction in order to drive a directional well while the entire drill string is rotating. An RSD could replace a PDMN in the BHA and the coating column rotated from the surface to rotate the drill bit, as discussed above. Preferably, a straight PDM can be placed above an RSD to trigger the RSD, which provides the steering capability for the BHA when conducting a coated drilling operation. Several advantages are achieved with this combination of PDM / RSD for coated drilling: (i) increased rotary speed of the drill compared to the rotating speed of the coating column for a higher ROP; (ii) a tightly spaced source of torque and energy for the drill; (iii) fewer engine stall problems than PDM alone since the torque generated from PDM can be supplemented by coating rotation; and (iv) improvements in hole cleaning while slowly rotating the coating during drilling.
    [00045] Figure 8 represents a rotatable steerable device (RSD) 110 that has a short bend for the drill face length and a long gauge drill. While driving, directional control with RSD is thus similar to directional control with PDM. Significant benefits during a coating drilling operation can thus be obtained while driving with the RSD, and drives the RSD with a PDM, and preferably with a PDM supplemented by the rotation of the coating column on the surface.
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    18/28 [00046] An RSD allows the drill to maintain the desired tool face and bending angle, while maximizing the drill column RPM and increasing ROP. With this technology, the well hole has a smooth profile when the operator changes the course. Local hook legs are minimized and the effects of tortuosity and other problems are significantly reduced. With this system, the ability to complete the well is optimized while improving the ROP and prolonging the life of the drill.
    [00047] Figure 8 represents a BHA for drilling a bypass well hole in which RSD 110 replaces PDM. The RSD in figure 8 includes a hollow, continuous, rotating rod 114 within a substantially non-rotating housing 112. The radial deflection of the rotating rod within the housing by a double eccentric ring meat unit 374 forms the lower end of the rod 122 pivot around a ball bearing system 120. The intersection of the central axis 130 of the housing 112 with the central axis 124 of the rod below the ball bearing system 120, defines folding 132 for directional drilling purposes. While driving, the folding 132 is maintained on a desired tool face and the folding angle by the double eccentric cam unit 374. To drill straight, the double eccentric cams are arranged so that the deflection of the rod is relieved and the central axis The rod below the ball bearing system 120 is placed in line with the central axis 130 of the housing 112. The aspects of this RSD are described in more detail below.
    [00048] RSD 110 in figure 8 includes a substantially non-rotating housing 112 and a rotating rod 114. The rotation of the housing is limited by an anti-rotation device 116 mounted on non-rotating housing 112. The rotating rod 114 is attached to the drill bit rotary 126 at the bottom of the RSD 110 and in the drive part 117 located near the upper end of the RSD via mounting device 118. A ball bearing assembly 120 mounts the rotating rod 114 in the non-rotating housing 112 near the end
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    19/28 lower than RSD. The spherical bearing assembly 120 restricts the rotating rod 114 to the non-rotating housing 112 in the axial and radial directions while allowing the rotating rod 114 to pivot with respect to the non-rotating housing 112. Other bearings rotate the rod in the housing rotatingly including bearings in the eccentric ring unit 374 and the cantilever bearing 372. From the cantilever bearing 372 and above, the rotating rod 114 is maintained substantially concentric with the housing 112 by a plurality of bearings. Those skilled in the art will appreciate that the RSD is shown simplistically in Figure 8, and that the actual RSD is much more complex than that shown in Figure 8. Also, certain aspects, such as bending angle and short lengths, are exaggerated for illustrative purposes.
    [00049] The drill rotation when implementing the RSD can be triggered on the surface, or it can be triggered by a PDM above the RSD, or both. In the first application, the rotation of the coating column 144 through the drilling frame on the surface causes the BHA to rotate above the RSD, which in turn directly rotates the rotating rod 114 and rotary drill 126. In the second application, a PDM without a the bend provided above the RSD drives the stem 114, which then turns the drill. The drill rotation can be supplemented by rotating the coating column from the surface while driving the PDM.
    [00050] While driving, directional control is achieved by radially deflecting the rotating rod 114 in the desired direction and in the desired magnitude within the non-rotating housing 112 at a point above the spherical bearing assembly 120. In a preferred embodiment, the deflection of rod is obtained by a 374 double eccentric ring meat unit, as described in US Patent Nos. 5,307,884 and 5,307,885. The outer ring, or flesh, of the double eccentric ring unit 374 has an eccentric bore in which the inner ring of the double eccentric ring unit is mounted. The inner ring has an eccentric hole in which the stem 114 is mounted. A mechanism is provided by which the orientation of each eccentric ring can be controlled
    Petition 870170086076, of 11/08/2017, p. 25/74
    20/28 independent of non-rotating housing 112. This mechanism is described in U.S. Order No. Serial 09 / 253,599, filed July 14, 1999 entitled Steerable Rotary Drilling Device and Directional Drilling Method. By orienting one eccentric ring relative to the other in relation to the orientation of the non-rotating housing 112, the deflection of the rotating stem 114 is controlled when it passes through the eccentric ring unit 374. The deflection of the stem 114 can be controlled when it passes through the eccentric ring 374. Stem deflection 114 can be controlled in any direction and any magnitude within the limits of eccentric ring unit 374. This stem deflection above the ball bearing system forms the bottom of the rotating stem 122 below the mounting of spherical bearing 120 pi vote in the opposite direction to the rod deflection and in proportion to the magnitude of the rod deflection. For directional drilling purposes, folding 132 occurs within the spherical bearing assembly 120 at the intersection of the central axis 130 of the housing 112 and the central axis 124 of the lower shaft rotating 122 below the spherical bearing assembly 120. The angle of bending is the angle between the two central shafts 130 and 124. The pivoting of the lower part of the rotating rod 122 causes the drill to tilt in the intended way to drill a deflected well hole. Thus, the drill tool face and folding angle controlled by RSD are similar to the drill tool face and PDM folding angle. Those skilled in the art will recognize that the use of a double eccentric ring meat is only a mechanism to deflect the drill with respect to a housing for directional drilling purposes with an RSD.
    [00051] While driving, directional control with RSD 110 is similar to directional control with PDM. The central axis 124 of the lower part of the rotating rod 122 is offset from the central axis 130 of the non-rotating housing 112 by the selected folding angle.
    For purposes of analogy, the mounting of the bearing package in the lower housing of the PDM is replaced by the mounting of the bearing
    Petition 870170086076, of 11/08/2017, p. 26/74
    21/28 spherical on RSD 110. The center of the spherical bearing assembly 120 is coincident with the folding 132 defined by the intersection of the two central axes 124 and 130 within the RSD 110. As a result, the folding housing and the bearing housing bottom of the PDM are not required with RSD 110. Placement of the spherical bearing assembly, folding and elimination of these housings results in an additional reduction of folding 132 for the distance from drill face 226 along the central axis 124 from the bottom rotating rod 122.
    [00052] When it is desired to drill straight, the inner and outer eccentric rings of the eccentric ring unit 374 are arranged such that the deflection of the rod above the ball bearing assembly 120 is relieved and the central axis 124 of the lower part of the rod rotary 122 is coaxial with the central axis 130 of the non-rotating housing 112. Straight drilling with RSD is an improvement over straight drilling with a PDM because there is no folding in the RSD housing, and the RSD housing does not need to be rotated. Housing stresses in the PDM will be absent and the well bore should be kept closer to the gauge size.
    [00053] As with the PDM, the axial spacing along the central axis 124 of the bottom of the rotating rod 122 between the fold 132 and the drill face 226 for RSD application could be as much as twenty times the drill diameter for obtain the primary benefits of this certificate of addition. In a preferred embodiment, the spacing between the bend and the drill face is four to eight times, and typically approximately five times, the drill diameter. This reduction in bending for the drill face distance means that the RSD can be inserted with less bending angle than the PDM to achieve the same construction rate. The folding angle of the RSD is preferably less than 0.6 degrees and is typically about 0.4 degrees. The axial spacing along the central axis 130 of the non-rotating housing 112 between the
    Petition 870170086076, of 11/08/2017, p. 27/74
    22/28 higher than RSD 110 and fold 132 is approximately 25 times the drill diameter. This RSD spacing is well within the comparable spacing of the uppermost end of the PDM power section for bending 40 times the drill diameter.
    [00054] The RSD 110 shown in figure 8 uses a short bend 132 for the length of the drill face 226 which is less than the limit of twelve times the diameter of the drill. The total gauge length of the drill is no longer than the minimum required length of 0.75 times the diameter of the drill, and at least 50% of the total gauge length is the substantially complete gauge. The bending angle in figure 8 is between the central axis 124 of the lower part of the rotating rod and the central axis 132 of the non-rotating housing 112. The first point of contact between the BHA and the wellhead for the motor of figure 8 is on the drill face. The second point of contact between the BHA and the wellhead is at the upper end of the drill calibration section. The third point of contact between BHA and the wellhead is highest in BHA. The bend of the wellhead is defined by these three points of contact between the BHA and the wellhead.
    [00055] Because RSD has a short bend for the drill face length and is similar to PDM in terms of directional control while driving, the primary benefits of this addition certificate are expected to apply while driving with RSD when inserting with a long gauge drill having a total gauge length of at least 75% of the drill diameter and preferably at least 90% of the drill diameter and at least 50% of the total gauge length is substantially complete gauge. These benefits include higher ROP, improved hole quality, smaller WOB and TOB, improved hole cleaning, longer curved sections, fewer collars employed, predictable construction rate, lower vibration, sensors closer to the drill, better profiles, coating insertion easier, and lower cementation cost.
    [00056] Several benefits are improved by more flexible folding
    Petition 870170086076, of 11/08/2017, p. 28/74
    23/28 short for the drill face length of the RSD compared to the PDM, which then means that a smaller bending angle can be employed. When combined with the long gauge drill, these factors improve the stability that is expected to perfect the borehole by reducing bore spiraling and drill rotation. Optimized weight transfer to the drill is also expected. The shortest bend for the drill face length of the RSD means that an acceptable construction rate can be obtained even with a housing connection at the lower end of the rotating rod 114. A pin connection can be used in this location and some improvement additional for the construction fee can be expected.
    [00057] An additional improvement is that the RSD can contain sensors mounted in the non-rotating housing 112 and a communication coupling in the MWD. The ability to acquire information near a drill and communicate this information to the MDW is improved when compared to the PDM. As with PDM, sensors can be supplied on the rotary drill when inserted with the RSD.
    [00058] The non-rotating housing 112 of the RSD may contain the anti-rotation device 116 which means that the housing is not smooth as with the PDM. The design of the anti-rotation device is such that it engages the formation to limit the rotation of the housing without significantly impeding the ability of the housing to slide axially along the well bore when the RSD is inserted with a long gauge drill. Therefore, the effect of the anti-rotation device on weight transfer to the bit is negligible.
    [00059] With the exception of the anti-rotation device, the non-rotating housing 112 of the RSD is preferably inserted smooth. However, there may be cases where a stabilizer can be used in the non-rotating housing near fold 132. One reason for using a stabilizer is that the frictional forces between the stabilizer and the borehole would help to limit the rotation of the non-rotating housing. O
    Petition 870170086076, of 11/08/2017, p. 29/74
    24/28 drag on the RSD is likely to be increased due to this stabilizer, as with a stabilizer on the PDM. However, with RSD, the effect of this stabilizer on weight transfer in the drill should be more than offset by the increase in drag due to the rotation of the drill string while driving.
    [00060] The orientation tool used to orient the bending angle of the PDM is no longer required because the RSD maintains directional control of the rotary drill. A straight PDM or electric motor can thus be placed in the BHA above the RSD as a source of rotation and torque for the drill.
    [00061] According to this certificate of addition, the connectors along the casing column need not be as expensive or robust as the prior art casing connectors for casing drilling operations. The coating connectors according to this present certificate of addition can thus be designed to withstand less torque than the prior art coating connectors, and preferably have a limit torque that satisfies the ratio:
    CCYT <5500 + 192 (OD-4,5) 3 Equation 1 [00062] Where the limit torque of the coating connector or CCYT is expressed in kg-meters, and the external coating device or OD is expressed in centimeters. The liner connection limit torque is thus the maximum torque that can be applied to the connector, since the excess torque of this value can theoretically result in limitation of the connector and thus fails, both mechanically (possible separation of the liner column) and hydraulically (possible leakage of fluid beyond or through the connection). In wells with a vertical or low slope, the normal force of the casing column on the wellhead wall is small, so that the limit torque would be proportional to the OD of the casing. In steep wells, however, the normal force is substantially the weight of the liner, which is a function of the density of steel and the square of the diameter of
    Petition 870170086076, of 11/08/2017, p. 30/74
    25/28 coating. In horizontal wells, the limit torque would be proportional to the OD hub of the casing column. The limit torque of connection can thus be determined for the worst case, that is, a horizontal well, then used in a vertical well, a well slightly inclined by less than about 5, and in a horizontal or substantially horizontal well. For many coating drilling applications, the CCYT according to the present certificate of addition can be significantly less than the prior art, and can be defined by the ratio:
    CCYT <5550 + 144 (OD-4,5) 3 Equation 2 [00063] which is approximately 60% of the limit torque capacity of torque connector connectors commonly used in coating drilling operations. In still other applications, the limit torque of the connector can be defined by the relation:
    CCYT = 5500 + 96 (OD-4,5) 3 Equation 3 [00064] In some shallow and / or vertical well applications, the reduced drag of the casing column in the well bore and the use of a speed engine comparatively low torque can allow the same lower torque regimes for the connectors, satisfying the ratio:
    CCYT = 5550 + 48 (OD-4,5) 3 Equation 4 [00065] According to the addition certificate, the BHA is much less inclined for this torque boost, and the PDM used can have a relatively low torque regime . Additionally, cladding joint connectors do not require special high strength, and in some embodiments they may have strength comparable to or may be standard API connectors (API RP 5C1, 18th Edition, 1999). Figure 6 represents a liner connector 60 according to the present certificate of addition that includes a tapered shoulder in the coupling for engagement with a lower end of an upper liner joint and an upper end of a lower liner joint, although the connectors cladding joint 60 as
    Petition 870170086076, of 11/08/2017, p. 31/74
    26/28 shown in figure 6 do not need to be expensive or robust in terms of drilling the prior art with liner connectors. Figure 7 shows an alternative liner connector 61 with a coupling connecting upper and lower joints, and tapered sealing surfaces at the end of each joint engaging a corresponding surface on the coupling. The connector 61 as shown in figure 7 can thus be similar to an API connection. This, and the reduced likelihood of connection failures, represents significant savings.
    [00066] According to the method of the certificate of addition, the bottom hole composition with the well hole motor as discussed above is assembled for use in a coating drilling operation. When assembling the plating column connectors, the compositing torque on the threaded connectors is controlled to be less than the limit torque that satisfies Equation 1, and preferably less than the limit torque that satisfies Equation 2. In many operations, the compounding torque can be further reduced to be less than the limit torque that satisfies Equation 3, and in some applications the compounding torque can be low enough to satisfy Equation 4. The threaded joints of the lining column are thus composed for a selected composition torque that is less than the limit torque, and can be selectively controlled to a desired level by controlling the maximum output of the energy clamps that supply the composition torque. The compositing torque for the cladding column connectors is preferably recorded to ensure that the compositing torque for each of the connectors is less than the limit torque.
    [00067] Yet another benefit of this addition certificate is that the size of the drill bit (reamer) can be reduced. Table 1 provides specific dimensions for a pilot drill and reamer in the open position. The hole widening is in excess of 40% between the pilot drill and the open reamer. If the hole enlargement can be
    Petition 870170086076, of 11/08/2017, p. 32/74
    27/28 reduced, significant savings would inherently result in drilling a smaller diameter well hole. The countersink hole diameter according to the prior art is in excess of about 125%, and more commonly around 130%, of the coating OD. Table 2 represents the same coating, with the same pilot drill size, and provides the smallest diameter reamer that results in a significant reduction in hole widening. As shown in Table 2, the hole widening can be less than 40% and, in many cases, less than about 35%. The ratio of the countersunk hole diameter to the coating OD as shown in Tables 1 and 2, which is less than 122% or less, preferably 120% or less, and commonly about 115% or less than the coating OD. According to this certificate of addition, it points to the significant advantages of this certificate of addition over the prior art.
    Table 1
    Coating size cm (inch) Pilot drill size cm (inch) Reamer (open) cm (inch) Hole enlargement Countersunk hole / OD coating 33.97 (13 3/8) 31.11 (12 1/4) 44.45 (17 1/2) 43% 131% 24.44 (9 5/8) 21.59 (8 1/2) 31.11 (12 1/4) 44% 128% 19.36 (7 5/8) 15.87 (6 1/4) 25.4 (10) 60% 132% 13.97 (5 1/2) 12.06 (4 3/4) 17.46 (6 7/8) 45% 125%
    Table 2
    Coating size cm (inch) Pilot drill size cm (inch) Reamer (open) cm (inch) Hole enlargement Countersunk hole / OD coating 33.97 (13 3/8) 31.11 (12 1/4) 40.64 (16) 31% 120% 24.44 (9 5/8) 21.59 (8 1/2) 27.94 (11) 29% 114% 19.36 (7 5/8) 15.87 (6 1/4) 21.59 (8 1/2) 36% 115% 13.97 (5 1/2) 12.06 (4 3/4) 15.55 (6 1/8) 29% 112%
    [00068] Reduce enlargement, therefore it will increase the penetration rate, and improve the safety of the reamer when cutting and when being recovered through the coating, and will reduce
    Petition 870170086076, of 11/08/2017, p. 33/74
    28/28 significantly drilling costs.
    [00069] It will be understood by those skilled in the art that the modality shown is exemplary, and that several modifications can be made in the practice of the certificate of addition. Consequently, the scope of the certificate of addition should be understood to include such modifications that are in the spirit of the certificate of addition, as defined by the following claims.
    Petition 870170086076, of 11/08/2017, p. 34/74
    1/4
    权利要求:
    Claims (10)
    [1]
    1. Method for drilling a well hole, using a downhole composition (10) including a steering device (110) having a rotating rod (114) within a non-rotating housing (112), the downhole composition (10) further including a drill bit (360) having a rotary drill bit (126) and a drill face (226) defining a drill cut diameter greater than an outer diameter of a casing column (144) inserted into the well with the rock bottom composition (10), characterized by comprising:
    attach the drill face (226) below the drill (360), the drill face (226) having a surface of uniform diameter therein while rotating along a central axis (124) of the lower portion of a rotating rod (122 ) below a spherical bearing system (120), the cutting diameter of the drill being 122% or less than the outer diameter of the casing column (144);
    space axially along the central axis (124) a fold (132) and the drill face (226) from 4 to 12 times the diameter of the drill (360);
    supply the rotating rod (114) attached to the rotating drill (126) at the bottom of the steering device (110) to drive a drive (117) located near the upper end of the steering device (110) through a mounting device (118 );
    rotating the rotating rod (114) and rotary drill (126) to drill the well hole; and, selectively define the direction of the borehole using a double eccentric ring meat unit (374) to cause a radial deflection of the rotating rod (114) within the housing (112), pivoting the lower end of the rod (122) in take a spherical bearing system (120), or align the central axis (124) of the rod (122) with the central axis (130) of the housing (112) to drill straight.
    [2]
    Method according to claim 1, characterized in that
    Petition 870170086076, of 11/08/2017, p. 35/74
    2/4 further comprise a long calibration section having a gauge length of at least 75% of the drill diameter.
    [3]
    Method according to claim 1, characterized in that it further comprises a positive positive displacement motor (straight PDM) placed above the steering device (110), where the steering device (110) is a rotatable steering device and is driven by the straight positive displacement motor.
    [4]
    4. Method according to claim 1, characterized in that it further comprises providing liner connectors (60, 61) along the liner column (144) connected by a torque lower than the liner connector limit torque, the torque coating connector limit satisfying the ratio:
    CCYT <5500 + 192 (OD - 4,5) 3 where CCYT is the limit torque of the sheath connector in meterkg, and OD is the outer diameter of the sheath column joints in centimeters.
    [5]
    Method according to claim 1, characterized in that it further comprises limiting the rotation of the housing using an anti-rotation device (116) mounted on the non-rotating housing (112).
    [6]
    6. Method according to claim 1, characterized by the fact that the folding angle of the steering device (110) is less than 0.6 degrees; and, the axial spacing along the central axis (130) of the non-rotating housing (112) between the uppermost end of the steering device (110) and the bend (132) is 25 times the diameter of the drill.
    [7]
    Method according to claim 1, characterized by the fact that the axial spacing along the central axis (124) between the bend (132) and the drill face (226) is five times the diameter of the drill.
    [8]
    8. Method according to claim 1, characterized in that the total gauge length of the drill (360) is greater than 0.75 times the diameter of the drill, and at least 50% of the
    Petition 870170086076, of 11/08/2017, p. 36/74
    3/4 gauge length is the full gauge.
    [9]
    9. System for drilling a well hole, using a well-bottom composition (10) including a well-hole motor having an upper power section with a central axis of power section and a lower central axis, the composition of downhole (10) further including a steering device (110) having a rotating rod (114) within a non-rotating housing (112), the downhole composition (10) further including a drill (360) having a rotary drill (126) and a drill face (226) defining a drill cut diameter greater than an outer diameter of a casing column (144) inserted in the well with the downhole composition (10), characterized by understand:
    liner connectors (60, 61) along the liner column (144), connected by a torque lower than the liner connector limit torque, the liner connector limit torque satisfying the CCYT ratio <5500 + 192 ( OD - 4,5) 3 , where CCYT is the limit torque of the casing connector in meterkg, and OD is the outer diameter of the casing column joints in centimeters; and, a drill face (226) attached below the drill (360), the drill face (226) having a surface of uniform diameter therein while rotating along a central axis (124) of the lower portion of a rotating rod (122) below a spherical bearing system (120), the cutting diameter of the drill being 122% or less than the outer diameter of the casing column (144);
    where the rotary drill (126) is attached to the rotating rod (114) and to the bottom of the steering device (110);
    where the borehole motor is a positive positive displacement motor (straight PDM) placed above the steering device (110), and the steering device (110) is a rotatable steering device and is driven by the positive positive displacement motor .
    [10]
    10. System according to claim 9, characterized
    Petition 870170086076, of 11/08/2017, p. 37/74
    4/4 for still understanding:
    a pin connection (42) at a lower end of the borehole motor; and a box connection at an upper end of the drill bit (360) for corresponding interconnection with the pin connection (42).
    Petition 870170086076, of 11/08/2017, p. 38/74
    1/3
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    同族专利:
    公开号 | 公开日
    WO2006110461A3|2009-03-19|
    GB2412134B|2007-01-31|
    WO2006110461A2|2006-10-19|
    BR0317401B1|2014-07-01|
    US6877570B2|2005-04-12|
    GB0622885D0|2006-12-27|
    AU2003297791A1|2004-07-29|
    GB0719908D0|2007-11-21|
    GB2441906A|2008-03-19|
    GB2429736A|2007-03-07|
    NO330594B1|2011-05-23|
    NO20052795L|2005-09-16|
    US20040112639A1|2004-06-17|
    WO2004061261A1|2004-07-22|
    GB2441906B|2010-09-01|
    CA2510081A1|2004-07-22|
    CA2604002A1|2006-10-19|
    GB2412134A|2005-09-21|
    NO343504B1|2019-03-25|
    NO20075263L|2008-01-10|
    BR0317401A|2005-11-16|
    GB0511681D0|2005-07-13|
    CA2510081C|2010-01-19|
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    GB2429736B|2007-07-25|
    CA2604002C|2010-10-05|
    AU2003297791B2|2007-03-29|
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    法律状态:
    2013-10-15| B06A| Patent application procedure suspended [chapter 6.1 patent gazette]|
    2014-03-04| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|
    2014-07-01| B16A| Patent or certificate of addition of invention granted [chapter 16.1 patent gazette]|Free format text: PRAZO DE VALIDADE: 10 (DEZ) ANOS CONTADOS A PARTIR DE 01/07/2014, OBSERVADAS AS CONDICOES LEGAIS. |
    2018-02-06| B08F| Application dismissed because of non-payment of annual fees [chapter 8.6 patent gazette]|Free format text: ADDITIONAL INVENTOR'S CERTIFICATE: |
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    2021-10-05| B21F| Lapse acc. art. 78, item iv - on non-payment of the annual fees in time|Free format text: REFERENTE A 18A ANUIDADE. |
    2022-01-25| B24J| Lapse because of non-payment of annual fees (definitively: art 78 iv lpi, resolution 113/2013 art. 12)|Free format text: EM VIRTUDE DA EXTINCAO PUBLICADA NA RPI 2648 DE 05-10-2021 E CONSIDERANDO AUSENCIA DE MANIFESTACAO DENTRO DOS PRAZOS LEGAIS, INFORMO QUE CABE SER MANTIDA A EXTINCAO DA PATENTE E SEUS CERTIFICADOS, CONFORME O DISPOSTO NO ARTIGO 12, DA RESOLUCAO 113/2013. |
    优先权:
    申请号 | 申请日 | 专利标题
    US10/320,164|US6877570B2|2002-12-16|2002-12-16|Drilling with casing|
    US10/320,164|2002-12-16|
    PCT/US2003/039131|WO2004061261A1|2002-12-16|2003-12-10|Drilling with casing|
    US11/103,186|US7334649B2|2002-12-16|2005-04-11|Drilling with casing|
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