The present invention is directed to a method of using a drill string configured for use within an underground environment. The method comprises the step of incorporating a sub having a fluid passage formed therein into the drill string, the sub having an elongate cartridge installed within the fluid passage, the cartridge retained within the fluid passage, but movable relative to the sub and having an outer surface comprising a concentric portion joined to a non-concentric portion. The method further comprises the steps of lowering a portion of the drill string carrying the sub into the underground environment, and generating fluid flow within the drill string and around the elongate cartridge such that the fluid flow causes the elongate cartridge to oscillate within the sub.
The present invention is also directed to a kit. The kit comprises a funnel sub having opposed first and second surfaces joined by a first fluid passage, the first fluid passage having a seat formed therein, and at least one deformable ball, each of which is sized, in its undeformed state, to be blocked from passing through the first fluid passage by the seat. The kit further comprises a receiver sub having opposed first and second surfaces joined by a second fluid passage, and an elongate cartridge sized for removable installation within the second fluid passage of the receiver sub. The cartridge has a pair of isolated cartridge chambers formed therein, in which one of the isolated cartridge chambers is configured to receive and retain deformed balls expelled from the funnel sub. The cartridge further has an outer surface comprising a concentric portion joined to a non-concentric portion.
The present invention is further directed to a jarring tool. The tool comprises a funnel sub having opposed first and second surfaces joined by a first fluid passage, the first fluid passage having a seat formed therein, and a receiver sub attached to the funnel sub and having opposed first and second surfaces joined by a second fluid passage. The tool further comprises an elongate cartridge installed within at least a portion of the second fluid passage of the receiver sub such that the cartridge is retained within the receiver sub but is movable relative to the receiver sub.
The cartridge comprises a first cartridge chamber formed within the cartridge and opening towards the first surface of the receiver sub, the first cartridge chamber having a single port formed therein. The cartridge further comprises a second cartridge chamber formed therein that opens towards the second surfaces of the receiver sub. The second cartridge chamber is isolated from the first cartridge chamber and has at least two ports formed therein. The cartridge further comprises a flange formed at the end of the cartridge and surrounding the second cartridge chamber. An outer surface of the flange comprises a concentric portion joined to a non-concentric portion.
In oil and gas drilling operations, there may arise a need to dislodge a stuck drill string within a wellbore by imparting a jarring impact force on the drill string or the bottom hole assembly.
The drilling system 10 works to advance the drill string 14 and the drill bit 16 down the wellbore 20 during drilling operations by rotating the drill string 14 and the drill bit 16. A bottom hole assembly 22 is connected to a terminal end 24 of the drill string 14 prior to the drill bit 16. The bottom hole assembly 22 may comprise one or more tools used in drilling operations, such as mud motors, telemetry equipment, hammers, etc.
The coiled tubing system 26 may be used to drill shallow wells or to perform well completion operations. Unlike the drill pipe or jointed pipe drill string 14, the coiled tubing drill string 30 does not rotate and is made up of a continuous string of pipe. This allows fluid to be continuously supplied to the wellbore 20 during operation.
A device capable of producing a jarring impact force on a stuck drill string 14 or coiled tubing drill string 30 is typically referred to as a “jar”. Jars known in the art operate mechanically or hydraulically. These jars contain moving parts and must be set or cocked to operate. In some cases, backward movement of the drill string 14 is required to set the jar. In coiled tubing 26 operations, the movement required to set the jar causes the coiled tubing 30 to move back and forth over the injector head 34 at the ground surface 18. This may cause the coiled tubing 30 to break down. In other cases, the jar may be set prior to drilling operations. In such instance, an operator runs the risk of the jar releasing and firing unintentionally.
The present invention is directed to a variable intensity and selective pressure activated jar that may be used with a drill pipe, jointed pipe, or coiled tubing drill string 14, 30. The jar of the present invention is described herein with reference to three embodiments, 100, 200, and 300. The jar 100, shown with reference to
The jar 200, shown with reference to
The jars 100 and 200 may be threaded or incorporated into any portion of the drill string 14 desired. However, preferably the jars 100 and 200 are threaded or incorporated into the bottom hole assembly 22 uphole from the motor and telemetry equipment. The jars 100 and 200 are most effective the closer they are to the drill bit 16.
The jar 300, shown with reference to
Turning now to
Both the first end 108 of the funnel sub 102 and the first end 114 of the receiver sub 104 have internal threads 118 formed therein (
The jar 100 is in fluid communication with the drill string 14 when the jar 100 is threaded directly into the drill pipe drill string 14. The outer body 106 and 112 of the jar 100 will contact the sides of the wellbore 20, like the rest of the drill string 14, once the drill string is lowered into the wellbore 20. The jar 100 will also rotate with the drill string 14 during drilling operations.
Turning now to
Fluid from the drill pipe drill string 14 may enter the first end 108 of the funnel sub 102, pass through the funnel element 122 and into the receiver sub 104. A cross-section of the receiver sub 104 is shown in
Referring now to
If fluid is continually pumped down the drill string 14, hydraulic pressure will build behind the ball 142 and within the portion of the drill string 14 uphole from the funnel sub 102. As hydraulic pressure builds within the drill string 14, the drill string will start to elongate. Eventually, the hydraulic pressure pushing on the ball 142 will exceed the amount of pressure the ball 142 can withstand. This will cause the ball 142 to deform and be expelled through the narrow neck 132 of the funnel element 122. The deformed ball 144 may be expelled through the funnel element 122 at a rate of 22,000-23,000 feet/second.
As the deformed ball 144 is expelled through the funnel element 122, fluid behind the ball will rapidly release through the narrow neck 132 of the funnel element 122. Fluid will rapidly release due to the significant amount of hydraulic pressure built up in the drill string 14. The rapid release of fluid will cause a dynamic event within the wellbore 20. The dynamic event is characterized by a sheer wave throughout the drill string 14 that causes a powerful jarring or jolting of the drill string 14 within the wellbore 20. The sheer wave is the result of the drill string 14 returning back to its natural state after being elongated by hydraulic pressure. The jarring or jolting of the drill string 14 works to dislodge the drill string 14 from its stuck point within the wellbore 20.
The jar 100 is capable of bi-directional jarring. This means that the dynamic event may jar the drill string 14 uphole from the jar 100 and the drill string or bottom hole assembly 22 downhole from the jar 100. The ease of dislodging the drill string 14 or bottom hole assembly 22 from its stuck point may be increased by using the surface equipment 12 to push or pull on the drill string 14 at the same time the jarring or jolting of the drill string takes place.
If the first dynamic event does not dislodge the drill string 14 or bottom hole assembly 22 from its stuck point, a second ball 142 may be pumped down the drill string 14 until it lands on the seat 134. Hydraulic pressure may again build behind the ball 142 until the pressure exceeds that which the ball can withstand and deforms the ball 142. The deformed ball 144 is expelled through the funnel element 122 causing the rapid release of fluid and a second dynamic event within the wellbore 20. This process may be repeated as many times as needed until the drill string 14 is dislodged from its stuck point within the wellbore 20. The use of the balls 142 to activate the jar 100 negates the need to set or cock the jar prior to firing. Thus, the jar 100 cannot be unintentionally fired downhole.
The balls 142 used to activate the jar 100 may have varying diameters. The greater the diameter of the ball 142, the greater the hydraulic pressure needed to deform the ball. The greater the hydraulic pressure built within the drill string 14, the more powerful the dynamic event. Thus, the greater the diameter of the ball 142, the more powerful the dynamic event or jarring of the drill string 14 and bottom hole assembly 22 that will take place within the wellbore 20.
The balls 142 are preferably solid and made of nylon, but can be made out of any material that is capable of deforming under hydraulic pressure and withstanding high temperatures within the wellbore 20. The balls 142 may also be porous and coated in a nano-particulate matter, the contents of which are a trade secret. The matter helps add friction between the ball 142 and the funnel element 122. The greater the friction between the ball 142 and the funnel element 122, the more hydraulic pressure will be required to extrude the ball through the funnel element. Due to this, the nano-particulate matter helps control the rate at which the deformed balls 144 are extruded through the funnel element 122.
In operation, an operator in charge of activating the jar 100 is typically provided with a set of balls 142 varying in diameter. The operator may start by first sending a control ball 142 down the drill string 14 to activate the jar 100. The control ball 142 is used to gain information about the conditions within the wellbore 20. This is important because each wellbore 20 may vary in depth, and the depth of the jar 100 within the wellbore 20 at the time the drill string 14 becomes stuck may vary. Due to this, the same size balls 142 may extrude at different pressures within each wellbore 20.
The operator may use any size ball 142 as a control ball. For example, the operator may choose the ball 142 with the smallest diameter as the control ball. This may be because the ball 142 with the smallest diameter will create the least powerful dynamic event, because it deforms under the least amount of hydraulic pressure. Once the control ball 142 has been extruded through the funnel element 122 and the jarring event takes place, the operator may try to move the drill string 14 within the wellbore 20. The operator can then determine what size ball 142 to use next based on the amount of movement of the drill string 14. For example, the control ball 142 alone may dislodge the drill string 14 or bottom hole assembly 22 from its stuck point. Alternatively, the drill string 14 may not move at all after using the control ball 142. In such case, it might be useful to jump up several sizes and use a ball 142 that creates a more powerful dynamic event within the wellbore 20. A larger sized ball 142 may be used as the control ball 142 if the operator knows beforehand that the drill string 14 will require a larger jarring event to attempt to dislodge it from its stuck point.
The operator may determine the amount of pressure required within the wellbore 20 to extrude each of the different sized balls 142 by watching the pressure gage at the ground surface 18. The pressure will build while the ball 142 is seated within the funnel element 122 and the pressure will drop once the deformed ball 144 is extruded. Once the operator determines the pressure required to deform and extrude the control ball 142 through the funnel element 122, the operator can determine the approximate amount of pressure required to deform and extrude the other sized balls.
Turning now to
With reference to
A series of fluid lanes 162 (
Continuing with
Fluid may flow from the funnel element 122 through the space 166 and into the receiver chamber 136. The elongate shoulders 164 of the elongate cartridge 146 direct fluid into the fluid lanes 162. The fluid lanes 162 direct fluid from the receiver chamber 136 into the ports 160 formed in the second cartridge chamber 150. Fluid in the second cartridge chamber 150 is directed into the fluid passage 140 in the receiver sub 104. The fluid passage 140 directs fluid into the drill string 14 and bottom hole assembly 22 downhole from the jar 100.
Turning to
Continuing with
Continuing with
Continuing with
The non-concentric portion 472 of the flange 464 and the non-concentric shoulder 480 cause the cartridge 450 to have a non-circular cross-section, as shown in
In alternative embodiments, the cartridge 450 may be modified differently than as specifically described herein, but still in a manner that causes the cartridge to have one or more non-concentric portions. In further alternative embodiments, other components of the jar 100 or the jar 200, described below, may be modified so as to have non-concentric portions resulting turbulent fluid flow and vibration of the drill string 14.
Turning now to
The landing sub 202 may be threaded into the drill string 14 or the bottom hole assembly 22 prior to starting drilling operations. The landing sub 202 is configured for receiving the jar 200. The landing sub 202 comprises an annular shoulder 204 (
If a landing sub 202 is not included in the drill string 14 already in the wellbore 20, the jar 200 may be attached to a locking mandrel and then pumped down the drill string 14. The locking mandrel may lock the jar 200 in a desired position within the drill string 14 or bottom hole assembly 22.
The jar 200 may also be sent down the drill string 14 on a wireline 208 (
Alternatively, a locking mandrel may be attached to the wireline tool 210 and jar 200. In this case, the wireline tool 210 sends the jar 200 and locking mandrel down the drill string 14 until they reach the desired position. Once in the desired position within the drill string 14 or bottom hole assembly 22, the locking mandrel may lock the jar 200 in place. The jar 200 may also be incorporated into the drill string 14 or bottom hole assembly 22 at the ground surface 18 prior to starting drilling operations.
Turning to
The pump down sub 206 is shown attached to a first end 224 of the jar 200. The pump down sub 206 has a cylindrical outer body 226 with a longitudinal internal fluid passage 228 (
A set of seals or vee packing 240 is disposed around the body 226 of the pump down sub 206 proximate its second end 232. Once the jar 200 is engaged with the landing sub 202, the vee packing 240 helps seal fluid from entering the space between the jar 200 and the drill string 14. This helps maintain hydraulic pressure within the drill string 14. The wireline tool 210 may also have vee packing 242 (
The cross-over sub 216 is used to engage with the landing tool 202 or a locking mandrel. The outer surface of the cross-over sub 216 has a top flange 244, a middle section 246, and a bottom section 248. The top flange 244 is formed proximate the first end 238 of the cross-over sub 216 and has a greater diameter than the middle section 246. The middle section 246 has a greater diameter than the bottom section 248. The bottom section 248 is formed proximate a second end 250 of the cross-over sub 216. As shown in
The cross-over sub 216 has a longitudinal internal fluid passage 252 that opens at its first end 224 and its opposite second end 250. The fluid passage 252 is in-line with the fluid passage 228 formed in the pump down sub 206. Fluid from the pump down sub 206 passes into the fluid passage 252 of the cross-over sub 216. Alternatively, the wireline tool 210 may have a fluid passage (not shown) to pass fluid between the tool 210 and the cross-over sub 216. Likewise, fluid may pass from a passage in the locking mandrel into the cross-over sub 216.
Turning now to
The outer surface of the funnel sub 218 has a top flange 262 and a bottom section 264. The top flange 262 has a greater diameter than the bottom section 264. When the funnel sub 218 is in the fluid passage 256 of the fluid release sub 220, the bottom section 264 of the funnel sub 218 engages with the annular shoulder 258 and the top flange 262 prevents the funnel sub 218 from moving past the annular shoulder 258. The cross-over sub 216 has a set of external threads 266 that engage with internal threads 268 on the fluid release sub 220 (
Like jar 100, a funnel element 270 is formed inside of the funnel sub 218. The funnel element 270 is shown in
When the funnel sub 218 is in the fluid release sub 220, fluid from the cross-over sub 216 passes through the funnel element 270 and into the fluid release sub 220. An O-ring or a seal 284 may be disposed around the bottom section 264 of the funnel sub 220 to prevent fluid from passing around the outer surface of the funnel sub 218 and into the fluid release sub 220. This helps maintain hydraulic pressure within the drill string 14.
Referring now to
The fluid release sub 220 further comprises a set of external threads 288 formed on its second end 289. The external threads 288 engage with internal threads 290 formed in a first end 291 of the receiver sub 222 (
Turning now to
As the deformed ball 144 is expelled through the narrow neck 280 of the funnel element 270, fluid will rapidly release from the funnel element 270 into the fluid release sub 220. As discussed with reference to jar 100, the rapid release of fluid will cause a dynamic event in the wellbore 20. The dynamic event is characterized by the powerful jarring or jolting of the drill string 14 or bottom hole assembly 22 to dislodge the drill string 14 or bottom hole assembly 22 from its stuck point within the wellbore 20. This process may be repeated as many times as needed until the drill string 14 or bottom hole assembly 22 is dislodged from its stuck point within the wellbore 20.
Fluid released into the fluid passage 256 of the fluid release sub 220 may pass through the fluid vents 286 and back into the drill string 14. The fluid vents 286 are tear-shaped. The tear-shape allows fluid to pass through the vents 286, but not the deformed balls 144. The tear-shape also prevents deformed balls 144 from getting lodged within the vents 286 and blocking the flow of fluid. The deformed balls 144 may only pass from the funnel element 270 into the fluid release sub 220 and into the receiver sub 222. Fluid that is passed back into the drill string 14 from the vents 286 may flow around the outer surface of the receiver sub 222 and continue through the drill string 14, as shown in
Turning now to
The second end 310 of the collar element 304 has a set of external threads 312. The external threads 312 may thread onto internal threads (not shown) formed in a bottom hole assembly 36 used in coiled tubing operations 26. The collar element 304 is attached to the coiled tubing drill string 30 and bottom hole assembly 36 prior to starting coiled tubing drilling operations 26.
If the coiled tubing drill string 30 or bottom hole assembly 36 becomes stuck within the wellbore 20 during operations, the jar 300 may be assembled. To assemble the jar 300, the funnel element 302 is first lowered or pumped down the coiled tubing drill string 30. The funnel element 302 has an elongated tapered outer surface 314. The funnel element 302 may fit within the collar element 304 by entering the first end 308 of the collar element 304. The collar element 304 is configured to hold the funnel element 302 in place within the coiled tubing string 30.
To pump the funnel element 302 down the coiled tubing drill string 30, the funnel element 302 may be inserted into an end 31 of the coiled tubing drill string 30 at the ground surface 18 (
Turning now to
The funnel element 302 will pass through the collar element 304 until it reaches the midpoint 316. When the funnel element 302 reaches the midpoint 316 the tapered outer surface 314 of the funnel element 302 will engage with the annular shoulder 324 of the collar passage 320. As the funnel element 302 moves down the collar passage 320 it will become lodged within the collar passage 320. This occurs because the upper portion of the funnel element 302 has a greater diameter than the neck 326 of the collar passage 320. Hydraulic pressure within the coiled tubing drill string 30 will keep the funnel element 302 lodged within the collar passage 320 during operation.
Like the jar 100 and 200, the funnel element 302 of the jar 300 has an internal fluid passage 328 that opens at a first surface 330 and an opposite second surface 332. The first surface 330 opens into an enlarged and recessed bowl 334. The bowl 334 tapers inwardly and connects with a narrow neck 336 that opens at the second end 332 of the funnel element 302. The bowl 334 has the shape of a frustum of a right circular cone having a slant angle of between 15 and about 20 degrees. Preferably this angle is 17.5 degrees. The connection between the bowl 334 and the narrow neck 336 forms a seat 338.
Once the jar 300 is assembled, the jar 300 may be activated. Like the jar 100 and 200, the jar 300 is activated by pumping a deformable ball 142 down the drill string 30. The same balls 142, 144 and operation described with reference to jars 100 and 200 may be used with the jar 300. The ball 142 is stopped once it reaches the seat 338 formed in the funnel element 302. The ball 142 prevents fluid from passing from the funnel element 302 into the collar passage 320 of the collar element 304. Hydraulic pressure builds on the ball 142 until it exceeds the pressure the ball can withstand. Once the pressure the ball 142 can withstand is exceeded, the ball will deform and be expelled through the narrow neck 336 of the funnel element 302. The deformed ball 144 will pass through collar passage 320 of the collar element 304 and may be retained within the bottom hole assembly 36. A screen (not shown) may be incorporated into the bottom hole assembly 36 to retain the deformed balls 144 but allow fluid to pass through. Alternatively, the deformed ball 144 may be expelled through the bottom hole assembly 36 and into the wellbore 20.
As the deformed ball 144 is expelled through the narrow neck 336 of the funnel element 302, fluid will rapidly release from the funnel element 302 into the collar passage 320 of the collar element 304 and into the bottom hole assembly 36. As discussed with reference to jar 100 and 200, the rapid release of fluid will cause a dynamic event in the wellbore 20. The dynamic event is characterized by the powerful jarring or jolting of the coiled tubing drill string 30 or bottom hole assembly 36 to dislodge the drill string 30 or bottom hole assembly 36 from its stuck point within the wellbore 20. This process may be repeated as many times as needed until the coiled tubing drill string 30 or bottom hole assembly 36 is dislodged from its stuck point within the wellbore 20.
The jars 100, 200, and 300 may be made of steel, aluminum, plastic, carbon fiber or other materials suitable for use in oil and gas operations. Preferably the jars 100, 200, and 300 are made of steel. The jars 100, 200, and 300 may also be covered in tungsten nitrate to harden the outer surface and help prevent the jars from rusting over time. Loctite may also be used on the threads on jars 100, 200, and 300. The Loctite helps secure the threaded connections to prevent the jars 100, 200, and 300 from becoming unthreaded during operation. Each of the jars 100, 200, and 300 may be easily disassembled and contained within a handheld carrying case.
A jar 100, 200, 300 may be assembled from a kit. Such a kit should include at least one funnel element 122, 270, 302, and at least one, and preferably a plurality of deformable balls 142. In some embodiments, the kit may further include at least one collar element 304.
In other embodiments, the funnel element 122, 270 of the kit may be incorporated into a funnel sub 102, 218 and the kit may further include a receiver sub 104, 222. Such a kit may also include at least one fluid release sub 220.
Although the preferred embodiment has been described in detail, it should be understood that various changes, substitutions and alterations can be made therein without departing from the spirit and scope of the invention as defined by the appended claims.
Number | Name | Date | Kind |
---|---|---|---|
3020964 | Graham et al. | Feb 1962 | A |
3535056 | Harbison | Oct 1970 | A |
4341272 | Marshall | Jul 1982 | A |
4889199 | Lee | Dec 1989 | A |
5797454 | Hipp | Aug 1998 | A |
6182775 | Hipp | Feb 2001 | B1 |
6290004 | Evans | Sep 2001 | B1 |
6318470 | Chang et al. | Nov 2001 | B1 |
6681860 | Yokley et al. | Jan 2004 | B1 |
6923255 | Lee | Aug 2005 | B2 |
8297365 | Dove | Oct 2012 | B2 |
8365818 | Schultz et al. | Feb 2013 | B2 |
8561688 | Evans | Oct 2013 | B2 |
9228402 | Strilchuk | Jan 2016 | B2 |
20090166026 | Akselberg | Jul 2009 | A1 |
20090283322 | Dove | Nov 2009 | A1 |
20140060854 | Baudoin | Mar 2014 | A1 |
20150136416 | Churchill | May 2015 | A1 |
20150226031 | Hekelaar | Aug 2015 | A1 |
20170247969 | Jones | Aug 2017 | A1 |
Number | Date | Country |
---|---|---|
166931 | Dec 2016 | RU |
2008146012 | Dec 2008 | WO |
2013175189 | Nov 2013 | WO |
Entry |
---|
Korean Intellectual Property Office, “Patent Cooperation Treaty PCT International Search Report”, Jun. 9, 2017, 3 pages, Republic of Korea. |
Korean Intellectual Property Office, “Patent Cooperation Treaty PCT Written Opinion of the International Searching Authority”, Jun. 9, 2017, 15 pages, Republic of Korea. |
International Bureau, “International Application Status Report”, May 24, 2013, 2 pages. |
International Bureau, “PCT International Preliminary Report on Patentability”, Nov. 25, 2014, 6 pages, Geneva, Switzerland. |
Patent Cooporation Treaty, “Written Opinion of the International Searching Authority”, Undated, 12 pages, Munich, Germany. |
Federal Service for Intellectual Property (Rospatent), Federal Institute of Industrial Property (FIPS), “Patent Search Report”, Apr. 3, 2020, 4 pages, Russia. |
Patent Office of the Russian Federation, Federal Institute of Industrial Property, “Office Action (Enquiry)”, Jun. 3, 2020, 9 pages, Russia. |
Number | Date | Country | |
---|---|---|---|
20230047958 A1 | Feb 2023 | US |
Number | Date | Country | |
---|---|---|---|
63300690 | Jan 2022 | US | |
62301398 | Feb 2016 | US |
Number | Date | Country | |
---|---|---|---|
Parent | 15443070 | Feb 2017 | US |
Child | 16380017 | US |
Number | Date | Country | |
---|---|---|---|
Parent | 16380017 | Apr 2019 | US |
Child | 17971951 | US |