Patent Application
20060266557
None.
1. TECHNICAL FIELD
The present invention relates generally to drilling bits used for drilling earth formations. More specifically, the present invention relates to a novel design for a directable jet nozzle for rock bits, which works in combination with a retaining system which defines limits of angular orientation.
2. DESCRIPTION OF RELATED ART
In the exploration of oil, gas, and geothermal energy, drilling operations are used to create boreholes, or wells, in the earth. These operations normally employ rotary and percussion drilling techniques. In rotary drilling, the borehole is created by rotating a tubular drill string with a drill bit secured to its lower end. As the drill bit deepens the hole, tubular segments are added to the top of the drill string. While drilling, a drilling fluid is continually pumped into the drilling string from surface pumping equipment. The drilling fluid is transported through the center of the hollow drill string and into the drill bit. The drilling fluid exits the drill bit at an increased velocity through one or more nozzles in the drill bit. The drilling fluid then returns to the surface by traveling up the annular space between the borehole and the drill string. The drilling fluid carries rock cuttings out of the borehole and also serves to cool and lubricate the drill bit.
One type of rotary rock drill is a drag bit. Early designs for drag bits included hard facing applied to steel cutting edges. Modern designs for drag bits have extremely hard cutting elements, such as natural or synthetic diamonds, mounted to a bit body. As the drag bit is rotated, the hard cutting elements scrape against the bottom and sides of the borehole to cut away rock.
Another type of rotary rock drill is the roller cone bit. These drill bits have rotatable cones mounted on bearings on the body of the drill bit, which rotate as the drill bit is rotated. Cutting elements, or teeth, protrude from the cones. The angles of the cones and bearing pins on which they are mounted are aligned so that the cones roll on the bottom of the hole with a controlled amount of slippage. One type of roller cone cutter is an integral body of hardened steel with teeth formed on its periphery. Another type has a steel body with a plurality of tungsten carbide or similar inserts of high hardness that protrude from the surface of the body. As the roller cone cutters roll on the bottom of the hole being drilled, the teeth or carbide inserts apply a high compressive load to the rock and fracture it. The cutting action of roller cone cutters is typically a combination of crushing, chipping and scraping. The cuttings from a roller cone cutter are typically a mixture of moderately large chips and fine particles.
When drilling rock with a roller cone cutter, it is imperative to remove the cuttings from the bottom of the hole. Failure to remove the cuttings from the hole-face will result in redrilling the cuttings. Redrilling rock cuttings substantially reduces the rate of penetration and causes premature failure of the roller cone drill bit. Roller cone drill bit cutting structures and bearing systems are both susceptible to premature failure when cuttings are not promptly removed from the hole-face when drilling. As an example, cutting structures may begin to track in a pattern that prevents normal progressive drilling. Build-up of cuttings or grindings of rock may quickly erode the metal surrounding the inserts, reducing the area of retention. This may allow inserts to be released in a catastrophic failure of the drill bit. Similarly, cuttings and grinds may build-up behind journal shirttail sections causing erosion and exposure of ball-plugs and seals, also resulting in catastrophic failure of the drill bit.
The importance of optimizing drilling hydraulics in oil and gas exploration has long been known. Drill bit manufacturers provided plastic slide rules to operators and contractors for many years, allowing them to calculate the various hydraulic components. In the late 1970's, Field Engineers used programmable calculators for the same purpose. In 1980, Reed Rock Bit® introduced an interactive microcomputer program for Field Engineers planning well drilling and hydraulics programs. A goal of these calculations, however made, was the proper selection of nozzles for the drill bits.
Various theories of hydraulics optimization have been advanced in oil and gas exploration. One popular theory relies upon maximization of a calculated numeric known as Hydraulic Horsepower. Another popular theory relies upon maximization of a calculated numeric known as Jet Impact Force. Both theories depend upon calculation of the pressure losses in the drilling system and allocating the optimum amount of remaining available pressure loss through the nozzles. Utilization of the theoretical optimum available pressure loss is achieved, in part, by increasing or decreasing the velocity through the nozzles. The velocity is adjusted by changing the cross-sectional area of the nozzle through which the fluid flows. Since nozzles in conventional drilling bits are interchangeable, this is easily accomplished.
Coincident to the practice of optimizing jet nozzle selection, it is known that the distance between the nozzle exit and the hole-face is an important factor in optimizing drilling hydraulics, and thus rate-of penetration. The closer the nozzle exit to the hole-face, the better the bottom hole cleaning properties. As the nozzle exit approaches the hole-face, there is less intervening turbulent flowing drilling fluid to interfere with the cleaning action of the fluid flowing from the nozzle. Conventional drill bits are limited by manufacturing practices as to how far up nozzle bosses can be manufactured, and still allow journals to be turned on machine centers. There is also a counterbalancing constraint requirement to provide sufficient return area across the drill bit for drilling fluid and cuttings to navigate the drill bit geometry in transit to the annulus of the well bore.
In addition to proximity to the hole-face, it has been determined that the angularity with which the fluid strikes the bottom of the hole can have a substantial impact on the hydraulic cleaning of the hole-face, and thus rate-of penetration. Drill bits and formations have different physical characteristics, leaving the optimum angle of nozzle direction relegated somewhat to experimentation between drill bits and formations. Additionally, the practice of high-speed drilling in which drill bits are rotated in excess of 100 rpm can change the optimum angle of nozzle direction. There is a counterbalancing constraint in which excessive angular disposition of the nozzle may contribute to cone erosion or seal exposure.
Numerous attempts have been made to provide a commercially practical directable nozzle design, as well as extended nozzle designs. U.S. Pat. No. 6,585,063 issued to Larsen discloses a multi-stage diffuser nozzle for rolling-cutter bits. The nozzle may comprise two or more portions, including a diffuser upstream of the nozzle outlet and a multi-outlet nozzle. The nozzle must be oriented as it is inserted and fixed in a given orientation.
U.S. Pat. No. 6,571,887 issued to Nguyen et al. discloses a nozzle retention body welded to the bit body between adjacent bit legs. The nozzle retention body may be of differing configuration and orientation, but it retains a generally conventional nozzle.
U.S. Pat. No. 6,390,211 issued to Tibbitts discloses a ball-mounted nozzle for a fixed-cutter bit or a rolling-cutter bit. The nozzle body is spherical and seats in a spherical receptacle. A retainer ring is used to secure the nozzle against rotation in the seat. U.S. Pat. No. 6,186,251 issued to Butcher discloses modifying the nozzle size or orientation with the intention of modifying the force balance.
U.S. Pat. No. 5,992,763 issued to Smith et al. discloses a nozzle having an indentation adjacent the nozzle opening or exit to enhance the flow of drilling fluid entrained near the face of the nozzle. U.S. Pat. No. 5,967,244 issued to Arfele discloses an “indexed” nozzle for fixed-cutter bits. The nozzle has a grooved exterior with corresponding grooves in a lock ring.
A primary disadvantage of several of the known art designs is that they are difficult and expensive to manufacture. Several of the designs are not compatible with the nozzle boss on standard rock bits having interchangeable nozzles. When modifications to the bit itself are required, the several costs associated with non-standard designs, such as tooling and machine set-ups, further increase the cost.
Another disadvantage of several of the known art designs is the time required for assembly of the drill bits. In the drilling industry, drill bit selection decisions are often made while drilling, in response to the drilling rate achieved and the condition of the dull bit removed from the hole. Several of the known art designs require welding operations which have proven to be an impediment to their acceptance in the drilling industry.
Another disadvantage of several of the known art designs is that they are not reusable. Sintered tungsten carbide nozzles are expensive, and operators expect to be able to reuse them. When dull drill bits are removed from the well, nozzles are removed and reused or recycled.
A significant disadvantage of the known art directable nozzle designs is that they are capable of being aligned in a manner that creates excessive turbulence around the nozzle boss and seal areas, resulting in hydraulic erosion of the steel around the nozzle boss, known-as “wash-outs,” and premature failure of the drill bit.
Another significant disadvantage of the known art directable nozzles is that they are capable of being aligned in a manner detrimental to the hydraulic performance of the drill bit. Still another significant disadvantage of the known art directable nozzles is that they are capable of being aligned in a manner which can result in improper alignment and premature bit failure from erosion of cones and/or exposure of journal bearing seals.
Thus it can be seen that, collectively, the known art fails to resolve the issue of a need for a directable nozzle that is inexpensive to manufacture, that is cost effective, that is easy to install, that is reusable, that has a restricted range of disposition, that avoids wash-outs, and that avoids poor hydraulic performance from misalignment.
The present invention is a significant improvement over that described in the above enumerated known directable nozzle designs. References to the present invention are intended to refer to one of more of the various embodiments disclosed of which can be inferred from the disclosure contained herein.
A principal advantage of the present invention is that it provides a nozzle system that has a designed restricted directability. As a result of this feature, rig floor assemblies by untrained personnel can be completed without risk of various problems associated with known directable nozzle designs. A benefit of this feature is that the present invention prevents excessive nozzle angularity resulting in internal turbulence around the nozzle boss and seal areas, hydraulic erosion and premature failure of the drill bit. Another benefit of this feature is that the present invention prevents excessive nozzle angularity resulting in inefficient hydraulic performance of the drill bit. Another benefit of this feature is that the present invention prevents excessive nozzle angularity resulting in improper alignment and premature bit failure from erosion of cones and/or erosion of shirttail regions and exposure of journal bearing seals.
Another advantage of the preferred embodiment of the present invention is that it is inexpensive and easier to manufacture than conventional designs. The design is compatible with the nozzle boss on standard rock bits having interchangeable nozzles. Another advantage of the present invention is the time required for assembly of the drill bits. No welding is required, and nozzle size selections can be made at the rig floor, immediately prior to connecting the drill bit to the drill string. This is critical as optimization of the nozzle selection requires knowledge of the drilling fluid and hydraulic system parameters at the time and depth the previous drill bit is removed from the wellbore.
Another advantage of the present invention is that it is reusable. Other advantages of the present invention will become apparent from the following descriptions, taken in connection with the accompanying drawings, wherein, by way of illustration and example, an embodiment of the present invention is disclosed.
In carrying out principles of the present invention, in accordance with a preferred embodiment thereof, a directable nozzle assembly for a rotary drill bit is disclosed, having a nozzle comprising a generally spherical body, and having an extension extending from the body. A passage extends through the body and extension portions. A seal is provided for sealing the nozzle to the nozzle boss area of the rotary drill bit. A removable retainer is provided having a hollow interior, a threaded external surface, an angle limiter surface, and an interior compression surface.
In another preferred embodiment, the angle limiter surface is frustum shaped. In another preferred embodiment, the interior compression surface is spherically shaped. In another preferred embodiment, the retainer has a wrench receptacle on a first end. In still another preferred embodiment, the retainer has a second end seal surface which restricts expansion of a packing seal. In the preferred embodiment, the limiter surface of the retainer prevents misalignment between a first portal of the nozzle body and the flow port of a rotary drill bit.
In an alternative preferred embodiment, the nozzle has a first portal on the spherical body and a second portal on the extension portion. An erosion resistant hollow sleeve is provided, having a collar portion with a spherical seat for receiving the nozzle body. The sleeve also has a hollow cylindrical body portion. A seal is provided for sealing the sleeve to the nozzle boss area of the rotary drill bit. In a more preferred embodiment, the body has a tapered end. In the preferred embodiment, the angle limiter surface of the retainer prevents misalignment between the first portal of the nozzle body with the hollow center of the sleeve. Additional features are presented in detail herein below.
A retainer 140 is provided, having a functionally unique structure. Retainer 140 has a nozzle boss connection means 144. In the preferred embodiment, nozzle boss connection means 144 is a threaded external surface 144. Retainer 140 may have a wrench receptacle 142 on its top surface, and a limiter surface 146 extends downward and inward from the top of retainer 140. In the preferred embodiment, limiter 146 is contoured for complementary engagement with extension 114. In a more preferred embodiment, limiter 146 forms a frustum, or conic section, for engagement with a generally cylindrical extension 114.
A contoured compression surface 150 extends downward from limiter 146. In a preferred embodiment, compression surface 150 is contoured for complementary engagement with nozzle body 112. In a more preferred embodiment, compression surface 150 forms a spherical segment. Also in a preferred embodiment, a small chamfer 148 is located between limiter 146 and compression surface 150.
As with conventional rotary drill bits previously described, rotary drill bit 10 has a flow port 12. A nozzle boss 14 is formed on rotary drill bit 10 for receiving nozzle assembly 100. In the preferred embodiment, nozzle boss 14 has a retainer connection means 22. In the preferred embodiment, retainer connection means is a threaded portion 22 for threaded coupling to retainer 140. A groove 16 is receivable of a seal 130. A bore relief 20 may separate threaded portion 22 from groove 16. A base 18 is formed at the bottom of groove 16. A nozzle seat 24 is formed below base 18. In the preferred embodiment, seat 24 is contoured for complementary engagement with nozzle body 112. In a more preferred embodiment, seat 24 forms a spherical segment.
Sleeve 160 has a body portion 170 that extends into flow port 12 beyond first portal 118 of nozzle 110. In a more preferred embodiment, a taper 172 is inscribed on the inside diameter of body 170. In this embodiment, a seal 180 is located in bore relief 20 of nozzle boss 14 to prevent drilling fluid from bypassing nozzle 110. In a more preferred embodiment, seal 180 is a packing seal.
The foregoing detailed description is to be clearly understood as being given by way of illustration and example, the spirit and scope of the present invention being limited solely by the appended claims. In particular, and by way of example and not limitation, it is well known to use alternative nozzle boss connection means to retain nozzles in rotary drill bits other than retainers with threaded connections. Conventional nozzle assemblies alternatively include nozzles having circumferential grooves and nozzle bosses with holes. In these assemblies, a “nail” is driven into the hole in the nozzle boss, for intersection with the circumferential groove to retain the nozzle. It would be readily apparent to anyone of ordinary skill in the art that the presently disclosed inventive embodiments can be incorporated into such assemblies. For example, the top to nozzle boss 14 can be modified to function as limiter surface 146, and multiple grooves can be formed on the surface of nozzle body 112 to accept the nail at various positions.
Still referring to
In the preferred embodiment, retainer 140 may have wrench receptacle 142 on its top surface and threaded external surface 144 for threaded and removable assembly in conventional rotary drill bits 10. Unique to the present invention, limiter surface 146 extends downward and inward from the top of retainer 140. In the preferred embodiment, limiter 146 is contoured for complementary engagement with extension 114. In a more preferred embodiment, limiter 146 forms a frustum, or conic section, for engagement with a generally cylindrical extension 114. The engagement with extension 114 with limiter 146 defines the maximum obtainable angular orientation of directable nozzles 110. This relationship is illustrated in
Nozzle passage 116 extends throughout body 112 and extension 114, with first portal 118 located on body 112 for entrance of the drilling fluid, and second portal 120 located on extension 114 for exit of the drilling fluid. Second portal 120 is generally smaller in diameter than first portal 118. The flow of the drilling fluid is thereby accelerated through nozzle passage 116, obtaining the desired high-velocity necessary to improve the performance of the rotary drill bit 10.
Referring again to
Similarly, in the preferred embodiment, rotary drill bit 10 has a nozzle seat 24 formed in nozzle boss 14 below base 18. In the preferred embodiment, seat 24 is contoured for complementary engagement with nozzle body 112. In a more preferred embodiment, seat 24 forms a spherical segment.
The geometric orientation of seat 24 is inverse to that of compression surface 150. In this configuration, as retainer 140 is progressively threaded into nozzle boss 14 of rotary drill bit 10, nozzle body 112 is compressed between compression surface 150 of retainer 140 and seat 24 of rotary drill bit 10. The compressive force on nozzle body 112 maintains nozzle 110 in place, while resisting the high outward force generated in nozzle passage 116 by the flow of the drilling fluid. The force against nozzle 110 is distributed in the threaded engagement between external threads 144 of retainer 140 and threaded portion 22 of nozzle boss 14.
As with conventional rotary drill bits previously described, nozzle boss 14 has a threaded portion 22 for threaded coupling to retainer 140, and a groove 16 for location of a seal 130, such as an o-ring seal. This advantageously allows convenient interchangeability between directable nozzle assembly 100 and conventional nozzle assembly 200 in rotary drill bit 10.
A principal advantage of the present invention is that by predefining the range of angular orientation of directable nozzles 110, catastrophic failure of rotary drill bit 10 can be avoided. This is particularly important because nozzles 110 can be easily assembled on the floor of the drilling rig by persons unfamiliar with the risk of improper orientation. Another advantage of this relationship is that retainers 140 can be provided which have different limiter 146 settings, and whereas retainers 140 are identified by the angle obtained with extension 114 engaging limiter 146. This can be used to obtain the specific angular orientation desired. The desired angle may be determined by drilling parameters and experimentation. Personnel can then select a retainer 140 identified to provide the angle, without the need for special alignment tools and gauges and training on their use.
As seen in the preferred embodiment disclosed in
As with conventional rotary drill bits previously described, nozzle boss 14 has a threaded portion 22 for threaded coupling to retainer 140, and a groove 16 for location of a seal 130, such as an o-ring seal. This advantageously allows convenient interchangeability between directable nozzle assembly 100 and conventional nozzle assembly 200 in rotary drill bit 10.
As seen in
The above described turbulence will occur even though portal 118 is maintained within flow port 12 by engagement of limiter 146 with extension 114. Over time, the turbulence will subject nozzle boss 14 to erosion. Seals 130 are therefore at increased risk of failure, as are retainer 140 and rotary drill bit 10. Sleeve 160 provides an erosion resistant channel that will tolerate the turbulence generated within flow port 12.
Referring again to
Sleeve 160 has a collar 162 that engages base 18 of nozzle boss 14, and resides in groove 16 in place of, or in conjunction with, o-ring seal 130. As rotary drill bits 10 are normally inverted for nozzle installation, this configuration allows collar 162 to suspend sleeve 160 in position while nozzle 110 is fitted into place.
A nozzle seat 164 is provided on collar 162, providing the function and benefit of nozzle seat 24 inside nozzle boss 14. In the preferred embodiment, seat 164 is contoured for complementary engagement with nozzle body 112. In a more preferred embodiment, seat 164 forms a spherical segment.
The geometric orientation of nozzle seat 164 is inverse to that of compression surface 150. In this configuration, as retainer 140 is progressively threaded into nozzle boss 14 of rotary drill bit 10, nozzle body 112 is compressed between compression surface 150 of retainer 140 and nozzle seat 164 of sleeve 160. The compressive force on nozzle body 112 maintains nozzle 110 in place, while resisting the high outward force generated in nozzle passage 116 by the flow of the drilling fluid. The compressive force on nozzle body 112 further secures sleeve 160 in place, compressed between nozzle 110 and base 18.
In the preferred embodiment, nozzles 100 and sleeves 160 are made of a hard metal, such as tungsten carbide, or titanium carbide. The hardness of the hard metal nozzles provides wear resistance to the abrasive forces associated with the high-velocity flow of the drilling fluid through the constricted diameter of nozzles 100, and the turbulence generated in the vicinity of sleeves 160.
In the preferred embodiment disclosed in
The foregoing detailed description is to be clearly understood as being given by way of illustration and example, the spirit and scope of the present invention being limited solely by the appended claims.
