Not applicable
Not applicable
The present invention relates to an oil well down hole tool that provides a fail-safe device and method, the device operable to improve the effectiveness of cleaning a wellbore which includes at least one surface casing and at least one liner through a combination of improved rotation and reciprocation of the drill string while allowing the casing and liners to be circulated independently.
It is typical to drill an oil well and run a series of casing which are cemented in place. In most cases, the casing will extend to a surface area and is called a surface casing. The innermost casing string is called the production casing. In some cases for reasons of economy there will be installed a liner. A liner is identical to casing except that it does not return all the way to the surface, but is instead suspended from the casing using a device known as a liner hanger. The final liner hanger which isolates the hydrocarbon bearing formation will typically be known as a production liner.
It is understood that where a production liner is hung from a production casing to form a wellbore, the production liner will be of substantially smaller diameter than the production casing. It is common practice to clean a wellbore before using it to produce hydrocarbons. Those familiar with the art of wellbore cleaning will understand that there are three important elements to consider when performing a wellbore cleanup. These are rotation of the drill pipe, reciprocation of the drill pipe and circulation of the cleaning fluid in the wellbore, and as a rule of thumb, the faster the better. Suffice it to say that excluding or restricting any one of these three actions, the speed and efficiency of the cleaning operation will be compromised.
Circulation is the primary method of removing unwanted debris from the wellbore. Good wellbore cleaning is a function of density, viscosity and annular velocity Annular velocity and viscosity conspire to determine the flow regime of the fluid, commonly referred to as laminar or turbulent. Chemicals such as solvents, surfactants and detergents used to clean the well work better in turbulent flow, and since it is easier to induce turbulent flow in low viscosity fluids, the preference is to prepare chemical washes with low viscosity. It is easier to carry debris from the wellbore with high viscosity fluids. A comprehensive wellbore cleanup will include pumping both high viscosity sweeping fluids and low viscosity chemical washes. These fluids are pumped as fast as possible to maximize the turbulence of the chemicals and the carrying capacity of the viscous sweeps. The fluid can be assisted further by using mechanical agitation by rotating and reciprocating the drill pipe.
Drill pipe consists of a tube connected by tool joints which include threaded couplings. The tool joints are typically larger diameter than the pipe body and when screwed together form a drill string. The outer surface consists of long slender pipe bodies with multiple large diameter protrusions or tool joints. As the drill pipe is suspended in the wellbore, it rarely sits concentric in the center of the wellbore. Due to gravity and well geometry, it will usually favour one side resulting in an eccentric shaped annulus. Cleaning fluids which are being pumped will favour the larger area of the annulus which is more open. This results in a dead volume being created under the drill pipe and between the tool joints where there is little or no flow.
The mechanical action of rotating the drill pipe serves to act as an impeller, drawing fluid from the main flow path under the drill pipe and consequently pushing debris out into the main flow path to be removed from the wellbore. The mechanical action of reciprocating the drill pipe uses the tool joints to drag debris upwards and when combined with the rotation causes an oscillating movement to assist in mechanical agitation of the fluid and to increase the turbulence of the fluid.
If during a wellbore clean-up there is no rotation or reciprocation, there may be significant areas of the wellbore which were not exposed to turbulent flow and will not have been properly cleaned by the chemicals and there may be debris trapped under the drill pipe. Further to this, when cleaning a wellbore with a production liner suspended from a production casing an operator will typically use what is called a tapered drill string, such that there is a larger diameter drill pipe in the production casing and small diameter drill pipe in the production liner. One reason this benefits wellbore cleaning is to maximize the annular flow rate and also to use the largest inner diameter pipe possible to reduce the pressure losses within the drill pipe while pumping.
Every drilling rig will have a practical limitation on the power of their pumps, where power is a function of pressure and flow rate. Therefore, drill pipe is typically selected to provide a balance between pressure loss while pumping down the pipe and flow rate when the returning fluid passes up the annulus. The following scenario is typical, where a 9⅝″ casing is set with a 5½″ production liner. Inside the wellbore is a tapered drill string consisting of 5″ drill pipe inside the 9⅝″ casing and 2⅞″ drill pipe inside the 5½″ casing.
The optimum flow rate for cleaning the 9⅝″ casing may be 13-18 barrels per minute (BPM), whereas the optimum flow rate for cleaning the 5½″ liner may be 3-5 BPM. If the operator pumps through the 5″ drill pipe and 2⅞″ drill pipe, he will most likely only be able to achieve a maximum of 5 BPM at the maximum pressure or power output of the pump. This is sufficient to clean the 5½″ liner but not the 9⅝″ casing. Therefore, it is now common practice to install a circulation device in the drill string immediately above the liner hanger. By opening this device, the operator no longer needs to pump through the 2⅞″ drill pipe and can now achieve the optimum flow rates to clean the 9⅝″ casing.
There is a drawback to using a tapered string, that the strength of the Upper Drill String is much higher than the strength of the Lower Drill String. For example, a 5″ drill pipe string may be rated to 50,000 ft. lbs. while the 2⅞″ drill pipe may be rated to 13,000 ft. lbs. When rotating the drill string to clean the well, if the drill string becomes stuck, it may result in over-torquing the 2⅞″ drill pipe resulting in a ‘twist off’ or failure due to torsion. This can happen quickly before the rig safety systems detect it. This will result in a costly fishing operation. Operators are so fearful of this that they limit or prohibit the rotation of 2⅞″ drill pipe when used with a tapered string for wellbore cleaning. Patents have been issued that relate to circulation of well fluid. Examples are listed in the following table, each listed patent of the table hereby incorporated herein by reference.
U.S. Pat. No. 6,279,657 discloses a circulating tool for circulating fluid in a borehole which features an obturating member to selectively open and close a circulation device, while simultaneously disengaging and engaging a splined drive mechanism. The tool is run immediately above a liner top and typically run with a tapered string for cleaning wellbores with a production casing and production liner as described previously. It works by allowing fluid to be pumped down through the string to clean the production liner, then can be opened by setting the tool on the liner top, opening the circulation ports and simultaneously disengaging a spline which allows the production casing to be cleaning at a high flow rate, and also while rotating the 5″ drill pipe. The 2⅞″ drill pipe does not rotate as the spline has disengaged. The limitation of this method is that it is not possible to reciprocate the drill pipe while cleaning the production casing since weight must be maintained to keep the circulation ports opened. Although the design of the tool does not prevent either reciprocation or rotation when cleaning the production liner, as disclosed previously, the operator may either limit or prohibit rotation for fear of a ‘twist off’.
GB2272923 discloses and apparatus for circulating fluid. The device is used in the same types of wellbores including a production liner and production casing, whereby the device is engaged with a liner top and by applying weight a circulation port is opened to allow displacement of the production casing. There are two types of tools disclosed which perform the same function. The limitation of these tools are that there is no way to rotate or reciprocate the string when the circulation ports are opened. Furthermore there is also the risk of ‘twist-off’ of the 2⅞″ drill pipe as disclosed previously.
U.S. Pat. No. 6,497,295 discloses a torque limiting tool which features a shear-able member which when an excess torque is detected it prevents a ‘twist-off’ by shearing the same member and sending a pressure signal to surface. This device can be used with U.S. Pat. No. 6,279,657 to overcome the issue of ‘twist-off’ except that the tool is not readily resettable. After removing a drill string from the production liner and due to the narrow clearance between the drill string and the liner, it is possible for debris or junk to become wedged between the two and the string becomes stuck. If this occurs it is highly desirable to be able to rotate the pipe to attempt to dislodge it. In this case if '295 shear-able member has been sheared, it will not be possible to rotate the string free resulting in an expensive fishing operation.
It is therefore desirable to use a device or system which allows unrestricted rotation and reciprocation while selectively opening and closing a circulation device to allow the production liner and production casing to the cleaned without compromising either three of these actions.
The apparatus of the present invention solves the problems confronted in the art in a simple and straightforward manner. The present invention provides a relockable shearing swivel tool which prevents accidental twist-off of a drill string, and which can be relocked by dropping an activation ball.
The present invention provides an oil well relockable shearing swivel downhole tool apparatus that includes an elongated tool body having upper and lower end portions, an upper section and a lower section.
An upper connection enables connection to an upper drill string section.
A lower connection enables connection to a lower drill string section.
An axial bore enables fluid communication between the upper and lower end portions.
The lower end portion of the tool body provides a ball seat and a ball retainer below the ball seat, inside the lower sub.
A first member is placed below the upper connection, with first interlocking portions on the first member.
A second member is placed in between the first member and the lower connection, and second interlocking portions on a second member.
A plurality of shear pins are placed on the tool body, the first and second interlocking portions being spaced apart a first distance in an initial position wherein relative rotation of the upper section relative to the lower section is prevented by the said shear pins.
A ball is sized and shaped to flow from the upper connection to the ball seat.
A drive nut is located above the ball seat.
A spring is placed in the tool body below the drive nut.
Wherein the ball is movable with the ball seat and the drive nut responsive to increased pressure in the bore above the ball to define a spring compressed position wherein the spring is compressed.
Wherein the ball is movable from the ball seat downwardly into the ball retainer responsive to increased pressure in the bore above the ball wherein the spring is released to lift the drive nut and the second member and wherein the first and second interlocking portions engage and interlock.
In one embodiment, the ball retainer has one or more bypass ports.
In one embodiment, the tool body includes a knocker sub below the upper connection.
In one embodiment, the shear pins form a connection between the knocker sub and the upper end portion of the tool body.
In one embodiment, the tool body carries a pump.
In one embodiment, the tool body includes an upper sub, a knocker sub and a lower sub.
In one embodiment, a threaded connection joins the upper sub to the knocker sub.
In one embodiment, a connection joins the knocker sub to the lower sub.
In one embodiment, the balls seat is in the lower sub.
In one embodiment, the drive nut is in the lower sub.
In one embodiment, the upper sub has a lower end and the lower sub extends upwardly above the lower end of the upper sub.
In one embodiment, the knocker sub has a lower end and the lower sub extends upwardly above the lower end of the knocker sub.
In one embodiment, the lower sub has intake ports that enable fluid intake to the pump at a position that is above the lower end of the upper sub.
In one embodiment, the spring is in the lower sub.
In one embodiment, the shear pins connect the upper sub to the knocker sub at a position above the lower sub.
The present invention can include a lockable weight set circulation tool that can be run in tandem with the relockable shearing swivel tool (see
For a further understanding of the nature, objects, and advantages of the present invention, reference should be had to the following detailed description, read in conjunction with the following drawings, wherein like reference numerals denote like elements and wherein:
Additional pump pressure is applied to force ball 53 down, past ball seat 53 and into ball retainer 44. Ball retainer 44 is located in bottom sub 29. Ball retainer 44 has lower face 50, O-rings 45 and internal abutment 48. When ball retainer 44 travels down responsive to pump pressure, it has face 50 that rests upon internal abutment 51 of bottom sub 29. Ball retainer 44 has bypass ports 49.
Once ball 53 is pumped below seat 46 and into ball retainer 44, spring 42 forces spring housing up to the position seen in
The relockable shearing swivel tool 56 and its components will now be discussed in more detail. The top sub 1 is an elongated member with an upper connection 2 to allow it to be connected to upper drill string 3. Axial bore 4 allows pumping of cleaning fluids. Spline 5 is provided to rotationally lock it to an upper drill nut 6. Male thread 7 allows connection to impeller nut 8. A series of castellations 9 rotationally lock to a lower rotator bearing 10. A series of helical grooves 12 which when the top sub 1 rotates acts as a screw pump. A series of bypass channels 13 pump the fluid through an upper thrust bearing 14. A series of holes 15 house torque shear pins 16 where the bypass channels 13 run between the holes 15. A shoulder area 17 accommodates upper thrust bearing 14.
The upper trust bearing 14 is locked to top sub 1 by a series of bolts 18 and is placed between the top sub 1 and a knocker sub 19 so that when the top sub 1 and knocker sub 19 rotate relative to each other, the upper thrust bearing 14 wears sacrificially. There are water courses 20 cut in the load bearing face of upper thrust bearing 14 which allows a pumped fluid to pass which act to cool and lubricate the upper thrust bearing 14. The upper thrust bearing 14 can be made of a bronze alloy but could be of other construction such as ceramics, polycrystalline diamond, ball bearing or other.
The knocker sub 19 has a face at an upper end which contacts the upper thrust bearing 14. A male thread 21 at the opposite which engages to and rotationally locks with the bottom sub 29. A series of castellations 22 rotationally lock to lower stator bearing 11. Internal cylindrical portion 23 houses the aforementioned top sub 1 where the internal cylindrical portion 23 and helical grooves 24 form the housing and rotor of the screw pump. The series of torque shear pins 16 rotationally lock the knocker sub 19 and top sub 1 such that when the top sub 1 is rotated by the upper drill string 3, torque is transmitted through it through the torque shear pins 16, through the knocker sub 19, through the bottom sub 29 and the lower drill string 31. The lower stator bearing 11 and lower rotor bearing 10 can be made of PCD polycrystalline diamond, but could be of other construction such as bronze alloy, ceramics, polycrystalline diamond, ball bearings or other.
Impeller nut 8 features an internal thread which locks it rotationally to the top sub 1 as well as carrying the tensile load of the tool body. Impeller nut 8 features a series of helical grooves 24 cut on the external surface which when placed inside an internal bore 25 of the bottom sub 29 forms rotor and housing of a screw pump. Rotary seals 26 form a hydraulic seal with the aforementioned internal bore 25. Two internal O-rings 27 form a hydraulic seal with the top sub 1. The two seals 26 combine to form an hydrostatic barrier between the axial bore 4 and annulus 28, thus ensuring cleaning chemicals and fluids can be pumped through the tool 56. Bottom sub 29 is an elongated member with lower connection 30 to allow it to be connected to lower drill string 31. Axial bore 4 allows pumping of cleaning fluids. Internal spline 32 engages lower drive nut 33. A series of intake ports 34 (e.g., formed by drilling a series of radial holes) immediately adjacent to the impeller nut 8, helical grooves 24 such that they allow annular fluid to enter the aforementioned screw pump mechanism. Radial threaded holes accommodate locking pins 35, an internal abutment 36 to locate stop ring 37; an internal abutment 38 to engage with spring housing 39.
Spring housing 39 is an elongated member which resides in the bottom sub 29 and forms the main structure in a sub-assembly which acts as the relocking element of the invention. Spring housing 39 features a threaded portion 40 at an upper end which engages with the lower drive nut 33. Holes which accommodate shear screws 41 temporarily lock to the aforementioned stop ring 37. A shaft accommodates spring 42 which is mounted about the shaft and compressed between the lower drive nut 33 and the stop ring 37.
During use, the tool body 62 is connected in the drill string between the upper drill string 3 and lower drill string 31. The upper drill string 3 is rotated which transmits torque and rotation through the tool body 62 to the lower drill string 31. The drill string can be rotated and reciprocated, allowing the well to be cleaned. It is also possible to function circulation tools to assist in the cleaning. If a predetermined torque limit is exceeded, the torque shearing pins 16 shear and the tool 56 becomes a swivel to allow the upper drill string 3 to rotate independently from the lower drill string 31, thus preventing an accidental twist-off of the lower drill string 31. Depending if the tool 56 is in compression or tension, the load axial load of the string will be borne by the upper thrust bearing 14 [compression] or the lower rotor/lower stator bearing 10 [tension] respectively. The rotation of the parts generates heat. The lower bearing 10 is cooled by circulating wellbore fluid through screw type fluid pump 65. When the upper 3 and lower components 31 of the tool 56 rotate with respect to each other, fluid is drawn from the annulus 28 through the entry ports and along the helical grooves 12 in the impeller nut 8 in an upwards direction. The fluid then flows between the lower stator bearing 11 and the lower rotor bearing 10 to cool it. Fluid is then drawn by the helical grooves cut in the top sub 1 and is diverted through the bypass channels 13 and through the water courses 20 which keep up the upper bearing 14 cool and lubricated.
When it is desired to relock the swivel to allow rotation to be applied between the top sub 1 and bottom sub 29, a ball 53 (or dart or other suitable or like object) can be pumped down to land on a ball seat 46 on the ball retainer 44. As pressure is applied, the shear screw 47 located between the spring housing 39 and stop ring 37 shear and spring housing 39 moves downwards compressing the spring 42. The spring housing 39 will then abut against the bottom sub 29 and as pressure increases the shear screws 47 related to the ball retainer 44 will shear, which releases the downward force and causes the spring 42 to move the spring housing 39 upwards. As this happens, the catellations 52, 53 between the upper drive nut 6 and lower drive nut 33 engage. Torque can now be applied between the upper 3 and lower drill strings 31 by the connection of the top sub 1, upper drive nut 6, lower drive nut 33 and bottom sub 29.
Lockable weight set circulation tool 100 of
The apparatus 100 disclosed uses a guide pin which locates in a continuous indexing slot milled onto an indexing sleeve, where each application and subsequent removal of weight to the tool shall cycle the tool the next indexing position. The device follows an infinite repeating cycle of CLOSED>OPEN>CLOSED>CLOSED>OPEN>CLOSED>CLOSED>OPEN, but can be reconfigured to follow other combinations such as CLOSED>OPEN>CLOSED>OPEN.
In
Spline mandrel 106 is an elongated member with threaded connection 105 to connect to the top sub 101, axial bore 104 to allow pumping of cleaning fluids, a spline 107 to rotationally lock it to drive mandrel 108 and allow the drive mandrel 108 and spline mandrel 106 to slide telescopically.
Shoulder 109 abuts against shoulder 145 of spline mandrel 106 which can hold the full weight of the drill string 3, 31 when required. A series of radial internal circulation ports 111 allow a flow path between the axial bore 104 and the annulus 112 when desired, which is straddled by seal 113. Index sleeve 114 is located at the lower end of male thread 115 which can accommodate a plug 116.
Drive mandrel 108 is an elongated member with a lower connection 117 to allow it to be connected lower drill string 31, axial bore 104 allows pumping of cleaning fluids. Threaded connection 119 at the upper end of drive mandrel 108 connects to the knocker sub 110. Internal spline portion of drive mandrel 108 engages with the spline 107 of spline mandrel 106. A series of holes accommodate shear pins 120 which mate with the drive mandrel 108. A series of radial external circulation ports 121 are provided to selectively circulate fluid from the axial bore 104 to the annulus 112. A hole is in drive mandrel 108 is provided to accommodate a guide pin 122. An internal seal bore 123 accommodates seals. A separate seal bore 124 accommodates plug 140.
Knocker sub 110 is fixed to the drive mandrel 108 by way of threaded connection. Knocker sub 110 is mounted onto the drive mandrel 108 and is used to restrict the slide-able movement of the spline mandrel 106 by shoulder 125 of top sub abutting against a shoulder of knocker sub 110.
Index sleeve 114 (
The plug 116,140 is connected to the lower end of the spline mandrel 106. It houses one of the aforementioned seals 135 which conspire with an O-ring 138 to form an hydraulic barrier. The plug 116 has an elongated end 139 with a bulbous feature 140 housing further O-rings 141 as well as a series of bypass ports 142, such that when the apparatus 100 is in the open 129 position, the O-rings 141 are stung into a seal bore on the drive mandrel 108 which seals the axial bore 104 preventing fluid from passing in either direction, and because the circulation ports are also in the open position, fluid pumped from the surface will exit the circulation ports and none can pass to the lower drill string 31. Furthermore, when the apparatus 100 is in any of the other positions, the bulbous feature 140 will not engage the seal bore 124 and fluid can be pumped through the axial bore 104, through the bypass ports 142, and through an annulus 143 created between the seal bore 124 and the elongated end 139.
In the initial “closed” 130 position, the tool has shear pins 120 intact which prevents axial compressive load causing the tool 100 to stroke, provided the axial load does not exceed the maximum shear strength of the shear pins 120. The selection of the shear pins 120 is important as this determines how the tool 100 may interact with other tools in the drill string. It also allows limited weight to be applied to the lower drill string 31 in the event it is required to drill cement or other debris in the wellbore without accidentally functioning the tool 100. In this position it is possible to pump cleaning chemicals and fluids downwards through the upper drills string 3 and lower drill string 31 to clean the production liner 55.
When it is desired to open the circulation port, a compressive load is applied to the tool 100. This is done by lowering the drills string 3, 31 until a landing sub 58 which is connected below the tool 100 lands onto a shoulder in the wellbore such as a liner top. As weight is continued to be applied, the shear pins 120 will rupture and the tool 100 will stroke moving the guide pin 122 along the indexing slot 128 until it reaches the cocked long 131 position.
The operator then raises the drill string 3, 31 until a tensile load strokes the tool 100 open and the guide pin 122 travels to the “open” 129 position aligning the internal circulation ports 111 and external circulation ports 121. The operator can then pump chemicals down the upper drill string 3 into the annulus 112 to clean the production casing 54.
The operator can then repeat the action of applying weight by lowering the drill string 3, 31 until the landing sub 58 engages the liner top to cycle the tool to the “closed” 130 position to allow further circulation of fluids through the production liner 55.
The device 100 can be cycled infinitely by the operator following repeating cycles of CLOSED>OPEN>CLOSED>CLOSED>OPEN>CLOSED>CLOSED>OPEN. The index slot 128 could be reconfigured to follow other combinations such as CLOSED>OPEN>CLOSED>OPEN.
The following is a list of parts and materials suitable for use in the present invention:
All measurements disclosed herein are at standard temperature and pressure, at sea level on Earth, unless indicated otherwise. All materials used or intended to be used in a human being are biocompatible, unless indicated otherwise.
The foregoing embodiments are presented by way of example only; the scope of the present invention is to be limited only by the following claims.
This application claims benefit of U.S. Provisional Application Ser. No. 62/221,788, filed on 22 Sep. 2015, which is incorporated herein by reference and priority of/to which is hereby claimed.
Number | Name | Date | Kind |
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6279657 | Carmichael | Aug 2001 | B1 |
6497295 | Carmichael | Dec 2002 | B1 |
20120234559 | Howlett | Sep 2012 | A1 |
Number | Date | Country | |
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20170081927 A1 | Mar 2017 | US |
Number | Date | Country | |
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62221788 | Sep 2015 | US |