Patent Application
20240344404
This disclosure relates generally to methods and apparatus for enhanced drilling operation with the use of Rotary Steerable System or RSS tool.
Prior art regarding axial and tortional protection exists for drilling systems, in particular associated with the use of Measurement While Drilling (MWD) or Logging While Drilling (LWD), as part of the drilling string. As an example of prior art, a patented application has been granted with the use of axial and tortional protection regarding the electronic module included within a MWD system. U.S. Pat. No. 8,640,795, granted on Feb. 4, 2014, with David W Jekielek as inventor, and also current co-inventor for this application. The U.S. Pat. No. 8,640,795 is incorporated herein by reference in its entirely for all purposes.
Background prior-art includes solution for shock and vibration reduction towards electronic positioned within tubular, whereby the electronics provides measurement and logging while drilling is active in a subterranean environment. Recent evolutions of drilling techniques may currently incorporate an RSS section, dedicated to the local directional of the drilling end-section. Therefore, there is a need for evolution towards reducing the shock and vibration of the RSS section.
Methods, apparatus, and products for drilling into the subterrain, in which a torsional shock/vibration dampening tool is positioned in the Bottom Hole Assembly above the drill bit to dampen the torsional shock/vibration resulting from the release of stored torsional energy after a struck drill bit or string releases from the subterrain.
In drilling a wellbore into the earth, such as in exploration and recovery of hydrocarbons, a drill bit is connected on the lower end of an assembly of drill pipe sections connected end-to-end to form a “drill string”. The upper end of the drill string is operatively connected to a rotary apparatus at surface, for example, drill head, rotary head, or double-head system, that rotates the drill string causing the bit to penetrate subsurface formations.
During wellbore drilling operations, varying physical characteristics and conditions of the subsurface materials being penetrated can cause fluctuations in the stresses and forces transmitted up the drill string. These fluctuating stresses may include vibration and shock impulses that cause the drill bit to “hop”, or stick in the case of PDC's, which in turn can cause the drill bit to cut slowly or unevenly through the formation. Also, the vibration and shock impulses can cause unexpected mechanical wear to components of the drilling system, and especially when the BHA contains more delicate electric components. These and other problems related to fluctuating drill string stresses and forces can increase the duration and cost of drilling operations.
For these reasons, the incorporation of electronic data-collecting devices into drill strings has become an increasingly common practice in the drilling industry. However, such data-collecting devices tend to be comparatively delicate and sensitive, and therefore are prone to damage when subjected to vibration and shock impulses that commonly occur during normal drilling operations.
Downhole tools are subjected to substantial dynamic forces and vibration during drilling. One problem encountered in all measurement-while-drilling systems, logging-while-drilling systems and rotary steerable systems (RSS) is that the drilling process involves axial, lateral, and radial vibrations and shocks which can interfere with smooth transmission of signals generated by the sensors and can severely damage the electronics and mechanical parts.
Sensitive downhole electronics, including but not limited to sensor packages, measurement-while-drilling (MWD) tools, steering tools, gyros, rotary drilling systems (RSS), or logging-while-drilling (LWD) tools, are particularly vulnerable to damage from vibration and shock during drilling. Electronics in downhole tools are often mounted in ways that reduce the energy that is felt by the electronics, but ultimately the vibration and shock still reduce the life cycle of the electronics and add fatigue and wear to the bottom hole assembly. Reducing shock and vibration felt by the electronics extends their life cycle, which saves valuable time and money that would be spent replacing or repairing the directional sensors and electronics. Accordingly, additional measures to minimize shock and vibration that reaches electronics are valuable.
In addition, the shock dampening module may need to be able to pass a MWD or other type of measuring device through the ID of the module. The module for the most part may need to be non-magnetic, such that it would not interfere with the directional sensors below and inside the module. Also, shock dampening modules may need to be stackable in series, to enhance and combine the dampening action.
Shock absorbers, also called “shock tools”, can be used to reduce the risk of damage to sensitive components such as, but not limited to, data-collecting electronic devices incorporated into drill strings due to vibrations and shock impulses resulting from these and other drilling-related practices. However, typical shock tools normally only address lateral shock and vibration.
During the process of directional drilling, real time bore hole positioning data as well as formation evaluation data is needed to effectively steer the well bore to the correct trajectory. Current RSS tools also incorporate similar downhole electronics and sensors, as the RSS tools are normally located right above the bit protecting them is even more difficult.
As a result of the proximity of the RSS and MWD tool to the mud motor and the bit, downhole electronics and sensors are exposed to an environment that has the highest vibration and shock loads in the drill string. To obtain accurate readings, the tool would need to be as close to the drill bit as possible, maintain a particular rotational alignment with the high side of a motor's bend and be separated by a minimum distance from any magnetic material in the drill string. In the situations where RSS is being used, the MWD system may not be positioned at a high side.
To optimize the rates of penetration (ROP) technology such as: increasingly aggressive drill bits, stronger mud motors, and devices such as agitators, which may specifically be designed to incite a vibration in the drill string, are being used to increase the rates of penetration (ROP) and extend the depth and reach of directional wells. As a result, the typical drilling environment may now be violent so that the RSS and MWD tools may not be able to survive for extended periods of time, resulting in failures of the tools that can cause significant time and monetary losses to the drilling operator as well as the electronics supplier that must replace or repair the damaged equipment.
When used with a Positive Displacement Motor (PDM), having a slight bend in the outer housing, directional drillers may redirect the path of the oil or gas well bore by simply allowing the PDM to rotate the bit, without rotating the drill pipe. This technique, called “sliding”, enables a change of course while drilling by reorienting the bend to a new known direction. A major advantage provided by RSS may be that the drill sting no longer needs to be stopped and oriented to make the slide. The orientation on a continuous basis, while rotating, minimizes the risk of differential sticking.
Starting in about 1985, oilfield service companies began using retrievable MWD systems, containing borehole sensor electronics and mud pulse transmitters to transmit downhole numerical data in “real time” to the earth's surface. By doing so, MWD systems could show the orientation of the bend in the drill. Starting in about 1986, Universal Bore Hole Orientation (UBHO) subs were adapted for use with MWD systems as the generally preferred technique for orienting directionally sensitive electronics in the MWD system. In the last few years, RSS is rapidly taking the place of the bent motor and the need to stop to orient the assembly. RSS has taken over the need to orient as the desired build, turn or drop has been programmed into the RSS.
The present form of the UBHO/Pulser sub has been used without major changes since 1992. However, beginning in about 2008, oilfield service companies began to use the technique of “horizontal drilling” to improve production of certain oil and gas bearing formations.
RSS has become very commonly utilized in directional drilling. RSS typically employs the use of specialized downhole equipment to replace conventional directional tools such as bent mud motors. They are generally programmed by the MWD engineer or directional driller. The RSS can be reprogrammed using surface equipment, typically using either pressure fluctuations in the mud column or variations in the drill string rotation, which the tool responds to, and gradually steers into the desired direction. In other words, a tool designed to drill directionally with continuous rotation from the surface, eliminating the need to “slide” a mud motor. These RSS systems may have electronics that need to be protected from drilling induced vibrations.
The nature of horizontal drilling, however, causes extended sections of the drill pipe to lay horizontally in the well bore, thereby creating torque and drag issues which effectively limit the horizontal distance that drilling rigs can legitimately reach.
In response, many service companies began to design drilling tools that can physically excite the drill pipe axially, along the length of the pipe, to release the torque and drag, like friction, of the horizontally disposed drill pipe against the borehole wall. By doing so, the excitation drilling tools make the pipe and drill bit move in a telescoping fashion to keep the drill pipe surface in a “dynamic state”, while in contact with the well bore. By constantly moving the drill pipe axially, frictional forces between the drill pipe and the formation wall may be greatly reduced. The result is that directional drillers may drill and slide faster and further, thereby reducing the number of days to drill the well.
A major drawback to generating axial movement of the drill pipe, however, is that the telescoping axial forces are hard on the MWD systems in the UBHO sub. MWD systems include downhole sensors, electronics and mechanical packaging that are sensitive to shock and vibration. Studies have shown that the introduction of axial excitation of the drill string may damage MWD systems once certain G-force levels are reached.
Design challenges exist due to the need for such systems to continue to operate reliably in extreme temperature conditions for potentially prolonged periods.
Furthermore, none of these methods or apparatus is adequate to sufficiently reduce torsional forces that are released after a stuck bit slips which is common in the shearing drilling process of PDC bits.
The following discussion on polycrystalline diamond compact (PDC) bits may be taken for example from https://tomax.no/about-stick-slip/, PDC bits are one of the most important material advances for oil drilling tools in recent years. Fixed-head bits rotate as one piece and contain no separately moving parts. When fixed-head bits use PDC cutters, they are commonly called PDC bits. Since their first production in 1976, the popularity of bits using PDC cutters has grown steadily, and they may be more common than roller-cone bits in many drilling applications.
While PDC bits can reach a higher rate of penetration compared to other bits, they are more prone to drilling vibrations.
From a bit type point of view, roller cone bits are known for generating axial vibrations, while PDC bits are known to generate stick-slip, bit whirl, and torsional resonance which play a significant factor in PDC bits performance.
Stick-slip vibration phenomenon has become an important risk element to evaluate in the planning of oil and gas well drilling. Because Polycrystalline Diamond Cutters (PDC) cut the rock by shear rotary force compared to the previous roller-cone bits that crushed the formations and required only a limited amount of energy to turn.
The stick-slip action is characterized by the absorption and release of energy as a function of the difference between static and dynamic friction. When stick-slip takes place at the end of a long drill-string, the phenomenon will produce accumulation and release of energy stored as several turns of twist in the string.
In the slip or release phase, the string may spin out of control, which would create stick-slip-associated destructive vibrations. Stick-slip occurring where the PDC cutters meet the rock has the potential to create the longest stick and most violent slip periods. Consequently, stick-slip initiated at the rock-cutting interface may be feared and may be responsible for most down-hole tool and tool joint overload failures in the industry.
Stick-slip can also be produced by the friction between the hole wall and the drill-string itself. In this interface, there is no potential for holding up the rotation for a long stick period and the stick-slip from friction is typically less threatening.
In a drilling operation, it is not uncommon that the bit may grab and get stopped by the surface into which the bit is drilling. While the bit might come to a stop, the motor keeps turning, winding up the drill string in a torsional way from the tip of the bit, with this winding up creating stored potential energy. At some point, the bit tip is freed from the surface, resulting in a very quick unwinding torsional release of the wound up stored potential energy along a very short part of the drill string, i.e., from the motor to drill bit. The resulting torsional vibrations caused by the quick unwinding release on such a short part of the drill string may be devastating to any equipment positioned between the motor and the drill bit, including RSS, guidance systems, and measurement tools.
Therefore, there is a need for a method and apparatus for reducing tortional forces protecting downhole components from shock and vibration that is not subject to one or more limitations of the prior art.
U.S. Pat. No. 7,654,344 issued Feb. 2, 2010 to Haughom et al., and assigned to Tomax A S, discloses a torque converter for use when drilling with a rotating drill bit. The purpose of the torque converter being to absorb impacts and bring about an axial movement of the drill bit when the torque exceeds a predetermined value. For this purpose, the torque converter is composed of two cylindrical string parts connected through the bearing elements. The string parts are connected to each other through helical elements in such a way that relative rotation of the two cylindrical string parts brings about axial movement, which unloads the drill bit.
U.S. Patent Publication Number 20120228029, published Sep. 13, 2012, to Reimers, and assigned to Tomax A S, discloses a method for reducing friction between interconnected outer and inner helical members of a downhole damper where the damper includes an outer damper body and an inner damper body, and where the outer and inner damper bodies are telescopically movable relative each other, the outer and inner damper bodies being biased in the extending direction, and where one of the outer and inner damper bodies are connected to a drill bit workable at a borehole face, and where the other of the outer and inner damper bodies is connected to a torque and force transmitting member, and where the outer and inner helical parts are arranged so as to retract the bit from the face when torque applied by the torque and force transmitting member exceeds a preset value, wherein the method includes letting a relative movement between the inner and outer body force lubricant to flow between the helical members.
U.S. Pat. No. 8,640,795, issue to Jekielek on Feb. 4, 2014, discloses a shock reduction tool for a downhole electronics package in which a tool string disposed in at least one tubular having upper and lower threaded connections to connect to a drill string. The patent states the tool string includes a shock reduction tool, which includes an anchoring tail piece axially and rotationally fixed to at least one tubular. The patent also discloses that a universal bore hole orientation (UBHO) mule-shoe sub is disposed at an upper end of the shock reduction tool, with a downhole electronics package coupled to the UBHO mule-shoe sub.
U.S. Pat. No. 9,605,527, issues to Reiderman et al, on Mar. 28, 2017, discloses reducing rotational vibration in rotational measurements utilizing an apparatus for mitigation of torsional noise effects on borehole measurements. The patent notes the apparatus may include a conveyance device; a sleeve having a sensor section, the sleeve rotatably disposed on the conveyance device; a sensor having at least one component disposed on the sensor section; and a driver coupled to the conveyance device and configured to rotate at least the sleeve sensor section. The patent also states the driver may rotate the sleeve sensor section independent of the conveyance device, and the driver may rotate the sleeve sensor section at a preset substantially constant rotational speed. Further, the sleeve may include at least one arm configured to selectively lock the sleeve to a surface in the borehole. Also, the driver may rotate the sleeve sensor section during measurement by the sensor, and the driver may selectively couple the sleeve.
U.S. Patent Publication No. 20170342781, published Nov. 20, 2017, to Reimers, and assigned to Tomax A S, discloses a regulating device is for use in a drill string between a drilling machine and a drill bit. The regulating device has a tubular female portion which at least partly encloses a tubular male portion; a helical coupling between the female portion and the male portion to allow a telescoping movement of the regulating device in both directions between a fully extended position and a fully retracted position, the movement of the regulating device occurring when there is a difference in rotational speed between the female portion and the male portion; a first biasing device which is arranged to exert a driving force to drive the regulating device towards its extended position; and a second biasing device.
US Patent Publication No. 20180171719 (Donald et al.) published Jun. 21, 2018, discloses drilling oscillation systems and shock tools for same. The publication discloses that the shock tool for reciprocating a drill string includes an outer housing, with the outer housing having a central axis, a first end, a second end opposite the first end, and a passage extending axially from the first end to the second end. As additionally disclosed, the shock tool includes a mandrel assembly coaxially disposed in the passage of the outer housing and configured to move axially relative to the outer housing. As further disclosed, the mandrel assembly has a first end axially spaced from the outer housing, a second end disposed in the outer housing, and a passage extending axially from the first end of the mandrel assembly to the second end of the mandrel assembly. As further disclosed the mandrel assembly includes a mandrel and a first annular piston fixably coupled to the mandrel. As also disclosed, the first annular piston is disposed at the second end of the mandrel assembly and sealingly engages the outer housing.
U.S. Pat. No. 10,407,999 (Pratt et al.) issued Sep. 10, 2019, discloses a vibration dampener configured for incorporation into a downhole measurement tool in a drilling system, for absorbing axial, lateral and torsional shocks and vibrations to protect measurement instrumentation located above the device during drilling. The patent notes the device includes: a main sleeve having a main cavity containing a main spring; an adapter connected to or formed monolithically relative to the main sleeve, the adapter configured for connection to a first tool component; a plunger configured to compress the main spring; a connector configured for connection to a second tool component, the connector attached to or formed monolithically relative to the plunger; a shaft extending between the adapter and the connector, the shaft provided with an anti-rotation structure; and one or more passages leading from the outside of the device into the main cavity. Also noted, the passages are provided to allow drilling fluid to enter the main cavity to act as vibration dampening fluid.
U.S. Pat. No. 10,458,226 (Kuroiwa et al.) issued Oct. 29, 2019, discloses a shock and vibration damper system and methodology, where the technique facilitates protection of a sensitive component, e.g. a well tool component, against shock and vibration. As disclosed, the sensitive component may be positioned in a mechanical chassis which is mounted in a housing, and wherein the mechanical chassis is mounted in the housing via a damper system which may comprise various vibration and shock absorbing components, such as a vibration damper, a transverse shock damper, and/or an axial damper. As noted, in drilling applications, the housing may be coupled into a drill string although the damper system may be used in other types of applications.
U.S. Pat. No. 10,533,376, issued Jan. 14, 2020, to Reimers, and assigned to Tomax, discloses a regulating device is for use in a drill string between a drilling machine and a drill bit. The regulating device has a tubular female portion which at least partly encloses a tubular male portion; a helical coupling between the female portion and the male portion to allow a telescoping movement of the regulating device in both directions between a fully extended position and a fully retracted position, the movement of the regulating device occurring when there is a difference in rotational speed between the female portion and the male portion; a first biasing device which is arranged to exert a driving force to drive the regulating device towards its extended position; and a second biasing device.
U.S. Pat. No. 10,683,710 (Christopher et al.) issued Jun. 16, 2020, discloses a device for isolating a tool from axial vibration while maintaining conductor connectivity. As noted in the patent, the device is provided for isolating, from shock and vibration, any down-hole tool housed within a drill string, while maintaining rotational alignment and providing a continuous electrical connection between the ends of the tool along a plurality of conductor paths. As further noted, the device increases down-hole tool life while reducing damage when operating in demanding environments.
U.S. Pat. No. 10,711,532 (Konschuh) issued Jul. 14, 2020, discloses the protection of downhole components from shock and vibration, utilizing a device, such as a snubber or shock absorber, for mitigating shock and vibration in downhole tools is provided. As disclosed, the device can have a body and an insert, which are separated by an elastomer to inhibit direct metal-to-metal contact there between. As further discloses the insert has a projecting portion located within a cavity of the body. As even further disclosed, the elastomer is disposed within a gap between the insert and the internal surface walls of the cavity, and the elastomer surrounds and contacts the projecting portion and the walls. As also disclosed, the elastomer may be molded, for example by flowing it into the cavity and subsequent hardening. Injection holes may be provided for molding. Also, the projecting portion may be shaped to limit rotation upon failure of the elastomer and/or may include ribs and splines for shock absorption, and the body may include a cap that contains the projecting portion to inhibit pull-apart.
U.S. Patent Publication No. 20210215038 (Schaeffer et al.) published Jul. 15, 2021, discloses a compressible load shoulder for dampening shock in downhole telemetry tool. As disclosed a mud pulse telemetry tool includes a dampener for reducing shock and vibration. Further, the mud pulse telemetry tool includes a housing having a shoulder formed along an inner surface thereof, the housing including an orifice formed therein. Also, the piston assembly is longitudinally movable in the housing between a retracted position and an extended position, wherein the piston assembly includes a poppet disposable in the orifice in the extended position and a piston connected to the poppet, and wherein, the dampener is disposed longitudinally between the piston and the shoulder, the piston being movable in contact with the dampener when the piston assembly is in the extended position.
https://www.neo-oiltools.com/discloses NeoTork, a downhole tool that manages torque generated by the drill bit as well as mitigating axial and torsional vibrations, protecting critical BHA components. The simple, unique design automatically controls downhole torque. When torque exceeds a preset limit, the tool contracts to reduce the drill bit depth of cut. The excess torque ‘stored’ in the system is slowly released as the drilling structure drills off.
The following drawings illustrate some of the many possible embodiments of this disclosure to provide a basic understanding of this disclosure. These drawings do not provide an extensive overview of all embodiments of this disclosure. These drawings are not intended to identify key or critical elements of the disclosure or to delineate or otherwise limit the scope of the claims. The following drawings merely present some concepts of the disclosure in a general form. Thus, for a detailed understanding of this disclosure, reference should be made to the following detailed description, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals.
It is to be understood that the following disclosure describes several exemplary embodiments for implementing different features, structures, or functions of the invention. Exemplary embodiments of components, arrangements, and configurations are described below to simplify the disclosure; however, these exemplary embodiments are provided merely as examples and are not intended to limit the scope of the invention.
Even if advantages and other features will become apparent from the following schematics, description and proposed claims, the proposed list of advantages may be limiting.
The proposed invention process may use a combination of some elements of the methods described in the existing art section, while adding specific usage, features and control method.
Referring now to
The vibration dampening tool of the present invention may provide protection for sensitive downhole electronics. As used herein, “sensitive downhole electronics” includes any electronic equipment utilized along the drill string, especially along the bottom hole assembly, that may fail due to exposure to drilling vibrations. Non-limiting examples of sensitive downhole electronics for which the present invention may provide protection, include but are not limited to sensor packages, measurement-while-drilling (MWD) tools, steering tools, gyros, rotary drilling systems (RSS), or logging-while-drilling (LWD) tools. For some non-limiting commercial instances, the desire to protect the guidance package, for example rotary drilling systems, may be an operational/design priority. The tool of the present invention is well adapted to protect the guidance package in such instances.
In some non-limiting instances, it may be desirable for some of the sensitive downhole electronics that the tool of the present invention provide a “non-magnetic” environment.
As shown in
If present, the top sub 1 housing may comprise a non-magnetic design to prevent magnetic interference with guidance equipment. Top sub housing 1 may comprise any suitable connector 2 to allow the connection of top sub section 102 to drill collar 203. It is understood that drill collar 203 may be replaced by one or more of torsional vibration dampening tool 100. Non-limiting examples of suitable connectors include threadless as well as threaded connectors. Non-limiting examples of threaded connectors include but are not limited to API threaded, proprietary threaded, or commercially available threaded ends. Non-limiting examples of threadless connectors include but are not limited to welding, mechanical mechanisms, and interlocking systems. While in the non-limiting embodiment as shown in
Top sub section 102 may further include connection shoulder 4 that engages with drill collar 203, and as described above, in other embodiments top sub section may be connected to the mud motor 201 or to the guidance system 204.
Referring additionally to
Additionally referring to
It is understood that the torsional vibration dampening tool 100 of the present invention may be positioned anywhere along the drill string, including being positioned somewhere in the BHA 350. Please note that the torsional vibration dampening tool 100 effectively divides the BHA 350 and by extension the drill string, into an upper portion that is up hole from the torsional vibration dampening tool 100, and into a lower portion that is downhole from the torsional vibration dampening tool 100. In the non-limiting embodiment as shown in
The term Bottom Hole Assembly 350 is typically known to those of skill in the drilling art. Typically, the components of a Bottom Hole Assembly 350 may include, but are not limited to, varying tool types from stabilizers, cross over subs, torque reducers, float subs, float valves, bull noses, z-bits, pony collars, and drill collars. These Bottom Hole Assembly items are utilized in the drill string to achieve connection changes, regulate pressure, help guide the string, add or decrease the length between specific tool types, and generally add weight to the string.
In general, commonly a drill string will utilize cross over subs, float subs, stabilizers, and some sort of collars. Specific applications will dictate if a certain BHA component is required, how many of each product, and where they are placed within the drill string 355. It is understood that the BHA 350 will be assembled to meet the well bore's specific needs.
The torsional vibration dampening tool 100 may be positioned anywhere on the BHA 350 or the drill string between the top/bottom of the BHA/string. In general, the torsional vibration dampening tool 100 may be positioned in and divides the BHA into a BHA upper portion containing the top end, and a BHA lower portion containing drill bit. As shown in
As displayed on
As displayed in
The top sub section 102 may further include seals, non-limiting examples of which include internals seals 11 and external seals 9, which allow for the compensating piston assembly 8 to move axially.
The top sub section 102 may further include a reservoir 4 for the compensating fluid/lubricant, and in communication with the compensating piston assembly 8. Compensating piston fluid/lubricant may be introduced to or removed from the reservoir 4 through an access port 15. Typically, there may be more than one access port 15, and any access port 15 may be positioned anywhere along the tool provided it is liquid communication with the reservoir. Potentially, more than one reservoir may be utilized in the present invention. As shown in
As referred to
The off-bottom energy absorbing elements 30, on-bottom energy absorbing elements 31, features 34, and/or features 38 may comprise a material, and/or may comprise a geometric design to be able to recoil or spring back into shape after bending, stretching, or being compressed. Suitable materials may comprise metals, polymers, and/or composite materials. Suitable materials and/or designs may be thought of as flexible, pliable, pliant, supple, plastic, elastic, springy, and/or rubbery.
As used herein, “on-bottom” will refer to instances in which the drill string is moving clockwise, with “off bottom” referring to instances in which the drill string is moving counterclockwise, and with “clockwise” and “counterclockwise” determine looking down into the formation.
In the non-limiting embodiment as shown, the top load bearing connection section 103 serves to connect the top sub section 102 and the stick slip section 101, and provide a load bearing connection therebetween. This transfers the load of stick slip shaft 18 onto the outer housing 20.
The top load bearing connection section 103 may the include stick slip shaft load/positioning threads 14. These positioning threads 14 may position the stick slip shaft 18 axially within the outer housing 20.
The top load bearing connection section 103 may also include the housing load bearing shoulder 20L of the outer housing 20. The load bearing connection 17 may be driven into the housing load bearing shoulder 20L by load bearing connection 17. Load bearing connection 17 may comprise any suitable threads, non-limiting examples include, API threads, machine threads, Acme threads, buttress threads, double shouldered, or proprietary threads. Load bearing connectors 2 and 17 will bear the same loads off bottom and on bottom.
The stick slip shaft 18 may extend from the bottom of the load ring 6 and into the bottom sub section 105. The stick slip shaft 18 may comprise at least one feature 38, as further shown in
In the non-limiting embodiment as shown, stick slip shaft 18 comprises three features 38 which interact with three complementary features 34 projecting from the outer housing 20, with this interaction helping to reduce/dampen forces acting upon drill string.
In the practice of the present invention, it should be understood, that the torsional vibration dampening tool 100 may comprise any one of the following numbers of features 38, or may comprise a number of features 38 ranging between or to/from any two of the following numbers, with the “following numbers” being: 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 12, 14, 16, 18, 20, 25, 30, 40, 50, 100, and 200.
In the practice of the present invention, it should be understood, that the number of complementary features 34 may be the same or different than the number of features 38, and that the torsional vibration dampening tool 100 may comprise any one of the following numbers of features 38, or may comprise a number of features 38 ranging between or to/from any two of the following item numbers: 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 12, 14, 16, 18, 20, 25, 30, 40, 50, 100, and 200.
The material of and shape of features 34 and 38 may be selected to provide dampening for a particular frequency of interest, for more than one frequency of interest, and/or for a range of frequencies of interest. It is possible for one torsional vibration dampening tool 100 to have features 34 and 38 of suitable material and shape to address one or more frequencies of interest.
In the practice of the present invention, it should be understood, that complementary features 34 and features 38 may have any suitable geometric shape that will provide sufficient torsional vibration dampening when features 34 and 38 are engaged by torsional forces, and may or may not have the same shape, such shapes may or may not complementary, such shapes may or may not be interlocking, but certainly features 34 and 38 interact. Suitable geometric shapes may comprise any regular or irregular three-dimensional shapes having linear and/or curvilinear surfaces. Suitable geometric shapes may comprise cross-sections comprising any two-dimensional regular geometric shapes, two-dimensional irregular shapes, and/or two-dimensional shapes comprising linear and/or curvilinear perimeters. Positive features include those that may be extending from the stick slip shaft 18 and the outer housing 20. Non-limiting examples of positive features include but are not limited to a protuberance, projection, bulge, overhang, dome, convexity, swell, jut, fin, piece, swelling, knob, block, bump, knot, mound, lump, nub, hump, and hill.
Negative features include those that recess into stick slip shaft 18 and the outer housing 20. Non-limiting examples of negative features include but are not limited to an alcove, nook, cubbyhole, cranny, embrasure, niche, indent, indentation, dent, indenture, cavity, depression, recess, pit, hole, indentation, hollow, concave, concavity, crater, valley, basin, well, bowl, groove, indent, slot, dip, pocket, trench, impression, furrow, trough, notch, dimple.
With or without deformable media 31, the outer housing 20 allows for drilling forces to be transmitted to stick slip shaft 18 through a direct or indirect resilient engagement between features 38 and features 34. As a non-limiting example, stick slip shaft 18 may move rotationally up to a 360 degrees rotation, and axially up to 0.25 inch [126 mm]. Possibly, there are embodiments which the rotational movement and axial movement may be greater or less than 360 degrees rotation and/or 0.25 inch [126 mm].
Thread pitch is a factor in determining movement per degree of rotation. As a non-limiting example, in an operation utilizing a relatively common 3.5 threads/inch, the interlocked threads of the bottom sub load bearing feature 53 and threads of the stick slip housing load bearing feature 48, will cause a very minor movement of drill bit tip 205B, on the order of 0.0008 inches [0.02 mm] per degree of rotation. Possibly, different thread configurations may yield different movement. Further the threads may be oriented so that this movement of drill bit tip is toward or away from the drilling surface. For example, left hand threads may be utilized to push the bit into the subterrain being drilled. Again, though, this axial movement is believed to be so small as to have no effect on drilling.
The stick slip shaft 18 resides in tool bore 56 which bore 56 is defined by torsion vibration dampening the torsional vibration dampening tool 100.
The housing load bearing shoulder 20L supports the forces resulting from the load being transferred into load bearing connection 17.
The load bearing connection 17 may define the external fluid/pressure passage 24 and internal fluid/pressure passage 27.
Stick slip section 101 may comprise one or more on-bottom stick slip bumper/cushion 31 and one or more off-bottom bumper/cushion 30, each of which are energy absorbing elements.
In the practice of the present invention, it should be understood, that the torsional vibration dampening tool 100 may comprise any one of the following numbers of off-bottom energy absorbing elements 30, or may comprise a number of off-bottom energy absorbing elements 30 ranging between or to/from any two of the following numbers, with the “following numbers” being: 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 12, 14, 16, 18, 20, 25, 30, 40, 50, 100, and 200.
In the practice of the present invention, it should be understood, that the number of on-bottom energy absorbing elements 31 may be the same or different than the number of off-bottom energy absorbing elements 30, and that the torsional vibration dampening tool 100 may comprise any one of the following numbers of on-bottom energy absorbing elements 31, or may comprise a number of energy absorbing elements 31 ranging between or to/from any two of the following numbers, with the “following numbers” being: 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 12, 14, 16, 18, 20, 25, 30, 40, 50, 100, and 200.
The bottom load bearing section 104 may include port 41 as shown in
The bottom loading bearing section 104 may serve to connect the bottom sub section 105 and the stick slip section 101 and provide a load bearing connection there between.
The bottom sub load bearing feature 53 may interact with the stick slip housing load bearing feature 48 to connect and provide a load bearing connection between bottom sub section 105 and stick slip section 101.
The fluid/pressure passages 43 are defined by stick slip housing load bearing feature 48 and bottom sub load bearing feature 53. Between drilling operations, fluid may be provided to and evacuated from passages 43 via port 41 which fluid provides lubrication between stick slip housing load bearing feature 48 and bottom sub load bearing feature 53.
Seal system 57 provides a seal between stick shift shaft 18 and bottom sub section 105, comprising one or more seal elements. The non-limiting embodiment as shown comprises a two O-ring in design.
Referring additionally to
In certain drilling operations/situations it is sometimes desirable to minimize the length of the BHA, such as but not limited to rotary steerable drilling. In some non-limiting embodiments of the present invention, it is desirable to minimize the length from the top 203T, as shown in
One advantage of minimizing the length is to position the end of the MWD tool 209 closer to drill bit 205. Another advantage of minimizing the length of the BHA is to reduce the amount of weight and length below the mud motor that will be subject to high RPM and high energy dynamic effects.
In order to place sensitive downhole equipment in stick slip shaft flow bore 56, the flow bore 56 must have a sufficient flow area through the tool to accommodate drilling fluid passing through as well as for passing the sensitive downhole electronics. In other words, the flow bore 56 must have a sufficiently large diameter such that the annular passage defined between the sensitive downhole electronics and the interior wall of the flow bore 56 is sufficient to accommodate the amount of well fluid that will pass there through during a well operation. This provides an advantage of allowing for a shorter bottom BHA by including sensitive downhole electronics in what is usually an unused hollow volume in the shaft. Without placing sensitive downhole electronics in the flow bore, it would have to be placed elsewhere in the BHA and increase the length of the BHA by at least the length of the sensitive downhole electronics, which could be on the order of 20 feet or more.
In a drilling operation, it may be not uncommon that the bit may grab and get stopped by the surface into which the bit is drilling. While the bit might come to a momentary stop or slow down, the motor and rig rotary keeps turning, essentially torsional winding up the drill string from tip of the bit and progressing up the drill string, with this winding up creating stored potential energy. At some point, the bit tip grab on the surface is released, resulting in a very quick unwinding torsional release of the wound up stored potential energy. The resulting torsional forces and vibrations caused by the quick unwinding release may be devastating (or cumulatively damaging/devastating) to any equipment positioned between the motor and the drill bit, including guidance systems and measurement tools.
One of the functions of the tool of the present invention is to protect the BHA and components thereof from damaging effect of released torsional energy. The methods, apparatus, and products of the present invention provide a reduction of the released torsional energy effects of at least 1, 5, 10, 15, 20, 25, 50, or more percent.
The present invention provides that more than one torsional vibration dampening tools 100 may be utilized in the drilling of a well. It should be understood there may be one or more frequencies that are of interest to be dampened. The present invention also anticipates that different torsional vibration dampening tools 100 could be designed/structured to cover the same/different frequencies of vibration through the selection of materials and geometry of features 34 and 38. Two or more tools may be located at various positions along the BHA. Two or more tools may be coupled together to create a turned assembly for the various drilling frequencies.
In the non-limiting embodiments as shown in
Various non-limiting geometries and arrangements of the various components are shown in
All the patents, applications, and publications, cited in this specification, are herein incorporated by reference.
The present disclosure is to be taken as illustrative rather than as limiting the scope or nature of the claims below. Numerous modifications and variations will become apparent to those skilled in the art after studying the disclosure, including use of equivalent functional and/or structural substitutes for elements described herein, use of equivalent functional couplings for couplings described herein, and/or use of equivalent functional actions for actions described herein. Any insubstantial variations are to be considered within the scope of the claims below.
There exists a need in the directional drilling art for improved products, apparatus, and methods for drilling into the subterrain when utilizing electrical components such as MWD, RSS, etc., that require a non-magnetic environment.
More specifically, there exists a need in the drilling art for improved products, apparatus, and methods for reducing torsional forces acting upon the drilling string while drilling into the subterrain where electrical components must pass through the bore of the non mag component(s) of the BHA, including the TVD component.
Even more specifically, there exists a need in the drilling art for improved products, apparatus, and methods for reducing torsional forces that are released upon the drilling string while drilling into the subterrain where the torsional reducing module must itself be non-magnetic.
Even more specifically, there exists a need in the drilling art for improved products, apparatus, and methods for reducing torsional forces that are released upon the drilling string while drilling into the subterrain and have a progressive or adaptive element to handle the torsional forces.
It is another object of the present invention to provide for improved products, apparatus, and methods for reducing torsional forces that are released upon the drilling string during drilling into the subterrain. These and other objects of the present invention will become apparent to those of skill in the art upon review of this specification, including its drawings and claims.
| Number | Date | Country | |
|---|---|---|---|
| 63458640 | Apr 2023 | US |
